DOCKETED

DOCKETED
Docket Number: 15-IEPR-01
Project Title: General/Scope
TN #: 206330
Document Title: 2015 Draft Integrated Energy Policy Report
Description: 2015 Draft Integrated Energy Policy Report
Filer: Raquel Kravitz
Organization: California Energy Commission
Submitter Role: Commission Staff
Submission Date: 10/12/2015 1:41:54 PM
Docketed Date: 10/12/2015

DRAFT COMMISSION REPORT
2015 DRAFT INTEGRATED ENERGY
POLICY REPORT
CALIFORNIA
ENERGY COMMISSION
Edmund G. Brown Jr., Governor
OCTOBER 2015
CEC-100-2015-001-CMD

CALIFORNIA
ENERGY COMMISSION
Robert B. Weisenmiller, Ph.D.
Chair
Commissioners
Karen Douglas, J.D.
Andrew McAllister, Ph. D
David Hochschild
Janea A. Scott
Stephanie Bailey
Jim Bartridge
Martha Brook
Guido Franco
Angela Gould
Judy Grau
Mike Jaske
Chris Kavalec
Suzanne Korosec
Rachel MacDonald
Chris Marxen
Jim McKinney
Ean O’Neill
Gordon Schremp
Charles Smith
Gene Strecker
Primary Author(s)
Raquel Kravitz
Project Manager
Heather Raitt
Program Manager
Robert P. Oglesby
Executive Director

ACKNOWLEDGEMENTS
Al Alvarado
Grace Anderson
Ollie Awolowo
Aniss Bahreinian
Kevin Barker
Sylvia Bender
Leon Brathwaite
Elise Brown
Matt Coldwell
Christine Collopy
Rhetta DeMesa
Anthony Dixon
Kristen Driskell
Pamela Doughman
Collin Doughty
Kristen Driskell
Catherine Elder
Andre Freeman
Nicolas Fugate
Eurlyne Geiszler
Elena Giyenko
Deborah Godfrey
Asish Goutam
Lynette Green
Courtney Smith
Aleecia Gutierrez
Pablo Gutierrez
Jason Harville
David Ismailyan
Erik Jensen
Melissa Jones
Linda Kelly
Don Kondoleon
Clare Laufenberg Gallardo
Laura Laurent
Virginia Lew
Grant Mack
Paul Marshall
Consuelo Martinez
Jennifer Masterson
John Mathias
Heather Mehta
Marc Melaina
Danielle Osborn Mills
Hazel Miranda
Farakh Nasim
Jennifer Nelson
Le-Quyen Nguyen
John Nuffer
Jacob Orenberg
Donna Parrow
Bill Pennington
Marc Pryor
Carol Robinson
Randy Roesser
Cynthia Rogers
Jana Romero
Ivin Rhyne
Patrick Saxton
Glen Sharp
Yongling Sing
Lori Sinsley
Courtney Smith
David Stoms
Peter Strait
Gene Strecker
Kirk Switzer
Laurie ten Hope
Abhilasha Wadhwa
Susan Wilhelm
Sonya Ziaja
iv

PREFACE
Senate Bill 1389 (Bowen, Chapter 568, Statutes of 2002) requires the California Energy
Commission to prepare a biennial integrated energy policy report that assesses major energy
trends and issues facing the state’s electricity, natural gas, and transportation fuel sectors and
provides policy recommendations to conserve resources; protect the environment; ensure
reliable, secure, and diverse energy supplies; enhance the state’s economy; and protect public
health and safety (Public Resources Code § 25301[a]). The Energy Commission prepares these
assessments and associated policy recommendations every two years, with updates in alternate
years, as part of the Integrated Energy Policy Report. Preparation of the Integrated Energy Policy
Report involves close collaboration with federal, state, and local agencies and a wide variety of
stakeholders in an extensive public process to identify critical energy issues and develop
strategies to address those issues.
v

ABSTRACT
The 2015 Draft Integrated Energy Policy Report provides the results of the California Energy
Commission’s assessments of a variety of energy issues facing California. Many of these issues
will require action if the state is to meet its climate, energy, air quality, and other environmental
goals while maintaining reliability and controlling costs. The 2015 Integrated Energy Policy Report
covers a broad range of topics, including energy efficiency, benchmarking under the Assembly
Bill 758 Action Plan, strategies related to data for improved decisions in Existing Buildings
Energy Efficiency Action Plan, building energy efficiency standards, the impact of drought on
California’s energy system, achieving 50 percent renewables by 2030, Renewable Action Plan
status, the California Energy Demand Forecast, the Natural Gas Outlook, methane emissions, the
Transportation Energy Demand Forecast, Alternative and Renewable Fuel and Vehicle Technology
Program benefits updates, landscape-scale planning efforts, transmission projects, the
California Independent System Operator energy imbalance market, the Desert Renewable Energy
Conservation Plan, climate change vulnerability and adaptation options, update on electricity
infrastructure in Southern California, an update on trends in California’s sources of crude oil,
and an update on California’s nuclear plants.
Keywords: California Energy Commission, energy efficiency, electricity demand forecast,
natural gas outlook, transportation energy demand forecast, Assembly Bill 758 Action Plan,
nuclear, Existing Buildings Energy Efficiency Action Plan, zero-net-energy, natural gas, methane
emissions, benchmarking, plug loads, crude by rail, climate adaptation, landscape scale
planning, Desert Renewable Energy Conservation Plan, Strategic Transmission Investment Plan,
Southern California reliability, drought, Alternative and Renewable Fuel and Vehicle
Technology Program benefits, energy imbalance market, drought
Please use the following citation for this report:
California Energy Commission. 2015. 2015 Draft Integrated Energy Policy Report. Publication
Number: CEC-100-2015-001-CMD.
vi

TABLE OF CONTENTS
Executive Summary .................................................................................................................................. 1
Introduction ............................................................................................................................................... 9
CHAPTER 1: Energy Efficiency ............................................................................................................ 17
Page
Existing Building Energy Efficiency .................................................................................................. 17
Utility Energy Efficiency Procurement ............................................................................................. 33
California Clean Energy Jobs Program ............................................................................................. 40
Zero-Net Energy ................................................................................................................................... 45
Recommendations ................................................................................................................................ 51
CHAPTER 2: Decarbonizing the Electricity Sector .......................................................................... 56
Greenhouse Gas Emissions From the Electricity Sector ................................................................. 57
Renewable Status ................................................................................................................................. 62
Renewable Action Plan Status ............................................................................................................ 67
Renewables and Reliability................................................................................................................. 74
Recommendations ................................................................................................................................ 86
CHAPTER 3: Strategic Transmission Investment Planning ........................................................... 88
Landscape-Scale Planning Efforts and Analytical Tools ................................................................ 89
Update on Ongoing Renewable Energy and Transmission Planning Efforts ........................... 90
Local Government Planning Activities ............................................................................................. 93
Planning with Stakeholders for Solar Development on Least-Conflict Lands in the San
Joaquin Valley....................................................................................................................................... 95
Renewable Energy Transmission Initiatives .................................................................................... 95
Landscape-Scale Planning Conclusions ............................................................................................ 96
Incorporating Landscape-Scale Planning into Transmission Planning Processes ...................... 97
California ISO Transmission Planning.............................................................................................. 98
Update to Transmission Projects to Meet the 2020 RPS ............................................................... 102
Regional Transmission Planning ..................................................................................................... 106
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Western States Transmission Planning Trends ............................................................................. 107
Multi-state Transmission Project Proposals ................................................................................... 110
Opportunities for Facilitating Future Potential Transmission Build-outs .............................. 112
Recommendations .............................................................................................................................. 117
CHAPTER 4: Transportation ............................................................................................................... 119
Achieving Greenhouse Gas Reduction and Clean Air Goals ...................................................... 119
2030 Climate Commitments ............................................................................................................. 123
Preliminary Transportation Energy Demand Forecast ................................................................ 125
Alternative and Renewable Fuel and Vehicle Technology Program Benefits Update ............ 140
Recommendations .............................................................................................................................. 152
CHAPTER 5: Electricity Demand Forecast ....................................................................................... 154
Background ......................................................................................................................................... 154
Summary of Changes to the Forecast .............................................................................................. 155
California Energy Demand Forecast Results ................................................................................. 156
Plans for the Revised Forecast .......................................................................................................... 164
Recommendations .............................................................................................................................. 165
CHAPTER 6: Natural Gas .................................................................................................................... 167
Assembly Bill 1257 Report ................................................................................................................ 167
Natural Gas Outlook ......................................................................................................................... 184
Recommendations .............................................................................................................................. 191
CHAPTER 7: Updates From the 2013 Integrated Energy Policy Report (IEPR) and the 2014
IEPR Update ........................................................................................................................................... 193
Electricity Infrastructure in Southern California ........................................................................... 193
Changing Trends in California’s Sources of Crude Oil ................................................................ 207
California’s Nuclear Power Plants ................................................................................................... 221
Recommendations .............................................................................................................................. 241
CHAPTER 8: California Drought ....................................................................................................... 246
Drought and Energy Impacts ........................................................................................................... 246
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Energy Efficiency and Water Appliances Regulations ................................................................. 254
Water Appliance Rebate Program ................................................................................................... 256
Water Energy Technology Program ................................................................................................ 259
State Agency Updates on the Drought ........................................................................................... 261
Recommendations .............................................................................................................................. 265
CHAPTER 9: Climate Change Research ........................................................................................... 267
Introduction ........................................................................................................................................ 267
Vulnerability and Adaptation Options ........................................................................................... 268
Initial Integration of Mitigation and Adaptation .......................................................................... 282
Climate Change and Air Quality Considerations ......................................................................... 285
U.S. Department of Energy, Partnership for Energy Sector Climate Resilience ....................... 287
Future Research Directions ............................................................................................................... 287
Recommendations .............................................................................................................................. 289
Acronyms ................................................................................................................................................ 291
APPENDIX A: Renewable Energy Action Plan Progress .............................................................. A-1
APPENDIX B: California and Washington Crude-by-Rail Projects ............................................ B-1
APPENDIX C: Crude-By-Rail Chronology of Safety-Related Actions ....................................... C-1
APPENDIX D: Full List of ARFVTP Projects Analyzed by NREL for 2015 IEPR Update ..... D-1
APPENDIX E: Status of Past IEPR Nuclear Policy Recommendations ....................................... E-1
LIST OF TABLES
Table 1: CPUC Goals and IOU Evaluated Savings for 2010–2012 ..................................................... 34
Table 2: CPUC Goals and IOU Reported Savings for 2013 and 2014 ............................................... 35
Table 3: 2013 and 2014 POUs Efficiency Savings and Expenditures ................................................ 37
Table 4: 2014-2023 Cumulative Efficiency Savings Potential for Publicly Owned Utilities .......... 40
Table 5: RPS Progress by Large Investor-Owned Utilities ................................................................. 65
Table 6: ARFVTP Investments by Primary Fuel Category Through June 30, 2015 ...................... 142
Table 7: Geographic Distribution ARFVTP Funding by Air District .............................................. 144
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Table 8: ARFVTP Funding Impacts on Infrastructure and Vehicle Deployment in California .. 145
Table 9: Projected Job Creation by Category ...................................................................................... 152
Table 10: Comparison of CED 2015 Preliminary and CEDU 2014 Mid Case Demand Baseline
Forecasts of Statewide Electricity Demand ........................................................................................ 157
Table 11: Statewide Baseline End-Use Natural Gas Forecast Comparison .................................... 189
Table 12: Water Consumption Rates for Thermal Power Plants ..................................................... 250
Table 13: First-Year Savings from Water Appliance Regulatory Standards .................................. 255
Table 14: Annual Savings from Water Appliance Regulatory Standards After Stock Turnover 256
Table 15: Proposed Water Energy Technology Program Budget .................................................... 260
Table 16: Projects Funded Since 2010 to Advance Research and Development for Existing and
Colocated Renewable Technologies ($70,257,605) .......................................................................... A-20
Table 17: Projects Funded Since 2010 to Advance Research and Development for Innovative
Renewable Technologies ($20,230,777) ............................................................................................. A-22
Table 18: Projects Funded Since 2010 to Promote Research and Development for Renewable
Integration ($109,245,960) ................................................................................................................... A-24
Table 19: Projects Funded Since 2010 for Proactive Siting of Renewable Projects ($9,196,414) A-28
Table 20: Full List of ARFVTP Projects Analyzed by NREL ............................................................ D-1
Table 21: Cumulative ARFVTP Investments Through June 30, 2015, by Investment Plan
Category .................................................................................................................................................. D-3
Table 22: Status of Past IEPR Nuclear Policy Recommendations ................................................... E-1
LIST OF FIGURES
Figure 1: California's GHG Emission Reduction Goals ........................................................................ 9
Figure 2: California’s GHG Emissions by Sector ................................................................................. 12
Figure 3: Single- and Multi-family Homes by Decade of Construction ........................................... 18
Figure 4: Existing Buildings Energy Efficiency Action Plan Implementation Schedule ..................... 20
Figure 5: Reduced Energy Consumption by Doubling Energy Efficiency ...................................... 21
Figure 6: Screenshot from California Solar Statistics Website ........................................................... 23
Figure 7: Comparison of Floor Space Covered by Benchmarking Strategies .................................. 26
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Figure 8: Proposition 39 Timeline .......................................................................................................... 44
Figure 9: Estimate of PV Capacity Required for ZNE Code Buildings ............................................ 47
Figure 10: Historic GHG Emissions From the Electricity Sector ....................................................... 57
Figure 11: Annual and Expected Energy From Coal Used to Serve California (1996-2026)* ........ 58
Figure 12: California Renewable Energy Generation From 1983-2014 by Resource Type (In-State
and Out-of-State) ...................................................................................................................................... 60
Figure 13: Megawatts Installed Solar Capacity for NSHP, 2007–2015 ............................................. 64
Figure 14: Potential Curtailment in 2024 at 40 Percent Renewables ................................................. 75
Figure 15: Potential Curtailment Scenario ............................................................................................ 76
Figure 16: Existing and Future EIM Entities ........................................................................................ 80
Figure 17: Potential Regional GHG Reductions With 40 Percent Renewables ............................... 82
Figure 18: West Texas Intermediate Crude Oil Monthly Spot Prices ............................................. 127
Figure 19: Preliminary Crude Oil Cost (Refiner Acquisition Cost) Forecast, (2012$) .................. 128
Figure 20: Preliminary Forecast of Cost per Mile (Compact Vehicles) ........................................... 129
Figure 21: California Light-Duty Vehicle Distribution by Fuel Type ............................................. 130
Figure 22: NHTSA’s Estimates of CAFE’s Cumulative Fuel Savings for the U.S. Fleet .............. 131
Figure 23: Preliminary California On-Road Gasoline Demand Forecast ....................................... 132
Figure 24: California Medium-/Heavy-Duty Vehicles Distribution by Fuel Type ....................... 132
Figure 25: Preliminary California On-Road and Rail Diesel Demand Forecast ............................ 133
Figure 26: Preliminary Transportation Natural Gas Demand Forecast ......................................... 134
Figure 27: Forecasted High-Speed Rail Electricity Consumption ................................................... 136
Figure 28: Preliminary Forecast of Total Transportation Electricity Demand .............................. 137
Figure 29: Aviation Fuel Consumption by Use and Type ................................................................ 138
Figure 30: Commercial Jet Fuel Consumption ................................................................................... 140
Figure 31: ARFVTP Investments by Fuel Category and Supply Chain Phase Through June 30,
2015 .......................................................................................................................................................... 142
Figure 32: Summary of Annual GHG Emissions Reductions Through 2025 From Expected
Benefits of 219 Funded Projects ........................................................................................................... 147
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Figure 33: Summary of Annual Petroleum Fuel Reductions From Expected Benefits Through
2025 .......................................................................................................................................................... 148
Figure 34: GHG Reductions From Expected and Market Transformation Benefits in Comparison
to Needed Market Growth Benefits..................................................................................................... 150
Figure 35: Statewide Baseline Annual Electricity Consumption ..................................................... 158
Figure 36: Statewide Baseline Annual Noncoincident Peak Demand ............................................ 159
Figure 37: Statewide Baseline Retail Electricity Sales ....................................................................... 160
Figure 38: Statewide Self-Generation Peak Reduction Impact ........................................................ 161
Figure 39: Statewide Self-Generation Consumption Impact ........................................................... 162
Figure 40: Climate Change Energy Consumption Impacts .............................................................. 163
Figure 41: Climate Change Peak Demand Impacts ........................................................................... 164
Figure 42: Common Case Natural Gas Price Results (Henry Hub Prices) ..................................... 186
Figure 43: Prices at Malin, Topock, and Henry Hub ......................................................................... 187
Figure 44: Prices Differentials (Point of Interest – Henry Hub) ...................................................... 187
Figure 45: Historical and Projected Natural Gas Production by Resource Type in the United
States ........................................................................................................................................................ 188
Figure 46: Natural Gas Burn for Power Generation in California (000s MMBtu) ........................ 190
Figure 47: Mid Demand Case Generation Fuel Sources 2015-2026 ................................................. 191
Figure 48: Baseline Projections Showing Local Capacity Surpluses/Deficits for the Los Angeles
Basin Local Capacity Area .................................................................................................................... 199
Figure 49: Baseline and Alternative Scenario Results Showing Local Capacity Surpluses/Deficits
for the Los Angeles Basin Local Capacity Area ................................................................................. 200
Figure 50: U.S. Crude Oil Production (1981-April 2015) .................................................................. 209
Figure 51: U.S. Crude Oil Imports (1990- 2015) ................................................................................. 210
Figure 52: U.S. Oil Rig Deployment Declines with Price ................................................................. 211
Figure 53: Global Crude Supply Imbalance (Q1 2013–Q1 2015) ..................................................... 212
Figure 54: Daily Brent Crude Oil Prices (2011–July 17, 2015) .......................................................... 213
Figure 55: Crude Oil Transportation by Rail Tank Car .................................................................... 214
Figure 56: California Crude Oil Imports via Rail Tank Cars ........................................................... 215
Figure 57: DOT Specification 117 Rail Tank Car ............................................................................... 219
xii

Figure 58: Seismic Hazard Categories at Diablo Canyon ................................................................. 232
Figure 59: Comparison of Diablo Canyon Response Spectra .......................................................... 233
Figure 60: Historical Hydroelectric Generation Compared to In-State Electricity Production .. 247
Figure 61: Water Supply for Natural Gas, Geothermal, and Solar Thermal Power Plants ......... 252
Figure 62: Global and California Temperature Anomalies .............................................................. 269
Figure 63: Vulnerabilities to Climate Change in the Electricity Sector........................................... 271
Figure 64: Hydropower Generation in July-September and Annual Water-Year Precipitation . 274
Figure 65: Sierra Nevada Region Temperature (°F) and Precipitation (inches) for Winter
(December, January, and February) in the Last 115 Years Plotted as Four-Year Averages ........ 275
Figure 66: Simulated Operations for Upper American River Project System During Three
Periods ..................................................................................................................................................... 277
Figure 67: Changes in Heating Degree Days in the NOAA Sacramento and San Joaquin Climatic
Zones ........................................................................................................................................................ 281
Figure 68: Percentage Contribution of NOx and CO2 Emissions by Different Sources ................ 286
Figure 69: Northwest Washington CBR Facilities ............................................................................. B-4
Figure 70: Southwest Washington and Northwest Oregon CBR Facilities .................................... B-6
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xiv

EXECUTIVE SUMMARY
California has a wealth of natural resources and human talent. It is one of the most desirable
places to live with stunning scenery including mountains, coastline, giant redwoods, and
majestic deserts. More than 38 million people call California home. It has a growing
economy, and the technology innovations that have come from this state are used
throughout the world.
California continues to be an international leader in environmental stewardship and is
advancing bold solutions to address climate change. On April 29, 2015, Governor Edmund
G. Brown Jr. signed Executive Order B-30-15, establishing a new statewide goal to reduce
greenhouse gas emissions 40 percent below 1990 levels by 2030. In his inaugural address,
Governor Brown said, “Taking significant amounts of carbon out of our economy without
harming its vibrancy is exactly the sort of challenge at which California excels. This is
exciting, it is bold, and it is absolutely necessary if we are to have any chance of stopping
potentially catastrophic changes to our climate system.” The Clean Energy and Pollution
Reduction Act of 2015 (Senate Bill 350, DeLeón, 2015) (SB 350) subsequently codified two of
the Governor’s goals for reducing carbon emissions: increasing renewable electricity
procurement to 50 percent by 2030, and doubling energy efficiency savings by 2030.
Californians are feeling the effects of climate change in more extreme fires, storms, floods,
and heat waves that cost lives and property damage, as well as decreasing snow-water
content in the northern Sierra Nevada. The potential human, ecological, and economic costs
of climate change are large, but California’s leadership to both reduce greenhouse gas
emissions and increase its resilience to climate change can make California stronger.
California is well on its way to reducing its greenhouse gas emissions to 1990 levels by 2020
as required by the California’s Global Warming Solutions Act of 2006 (Assembly Bill 32,
Núñez, Chapter 488, Statutes of 2006). The Governor’s 2030 target strengthens the state’s
position to meet its long-term goal of reducing greenhouse gas emissions 80 percent below
1990 levels by 2050. Meeting the 2050 goal will require a deep transformation of California’s
energy system – it will require the innovation for which California is known.
Energy Efficiency is Key in All Pathways to a Low-Carbon Energy System
In his 2015 inaugural speech, Governor Brown set a goal to double the efficiency savings
achieved at existing buildings and make heating fuels cleaner. SB 350 codified this goal into
law and requires the Energy Commission to assess and report progress toward the goal. In
September 2015, the California Energy Commission adopted a roadmap to reach this goal
by 2030. The roadmap, called the Existing Buildings Energy Efficiency Action Plan, describes a
group of goals and strategies which, if put fully into action, would accelerate the growth of
energy efficiency markets, more effectively target and deliver building upgrade services,
improve quality of occupant and investor decisions, leading to vastly improved energy
performance of California's existing buildings. The action plan includes strategies to
enhance government leadership in energy and water efficiency, such as leading by example
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to improve the efficiency of public buildings, developing a new statewide benchmarking
and disclosure program, encouraging local government innovations, and facilitating the
application of energy codes to existing building upgrade projects. Providing building
owners and their agents easy access to the building energy use data that are needed for
improved decision-making is another key goal of the plan. The action plan also focuses on
high-quality building upgrades and increased financing options. The action plan is designed
to help achieve greenhouse gas reduction goals and help consumers save money and enjoy
more comfortable homes through energy efficiency.
California continues to make progress on other energy efficiency priorities as well. Utilityrun
programs are another important part of the state’s strategy to advance energy efficiency.
The California Public Utilities Commission has oversight of energy efficiency programs
administered by investor-owned utilities, while the publicly owned utilities implement and
monitor their own programs. These programs help reduce emissions using the lowest-cost
energy resource option. SB 350 will expand the types of efficiency programs available, while
also tying incentive payments to measurable efficiency results. Energy efficiency upgrades
in California’s schools are being realized as result of funding available from the Clean
Energy Jobs Act (Proposition 39). The act funds eligible energy measures such as energy
efficiency upgrades and clean energy generation at schools. The Energy Commission is
primarily responsible for administering Proposition 39 for kindergarten through 12th grade
schools. For newly constructed low-rise homes, the state is steadily moving toward
implementing zero-net energy buildings for 2020 in which energy efficiency is part of an
integrated solution. Outstanding issues remain, however, including needing to identify
compliance pathways when on-site renewable generation is not feasible and the appropriate
role for natural gas in zero-net-energy buildings. Throughout these programs, the primary
challenge is to build a technical and regulatory foundation for orchestration of energy
efficiency and all other feasible distributed and customer-sited clean energy resources.
Decarbonizing the Electricity Sector
Another important tool in meeting climate and air quality goals is decarbonizing the
electricity sector as part of an integrated approach to reducing emissions from energy use.
California has made great strides in reducing greenhouse gas emissions from the electricity
sector. In 2013, emissions from the electricity sector were already about 20 percent below
1990 levels. California uses renewable energy to serve about 25 percent of its electricity
consumption and is on a solid trajectory to meet the statute’s Renewables Portfolio Standard
of 33 percent by 2020. As part of his climate policy, Governor Brown set a goal of increasing
California’s electricity derived from renewable sources from one-third to 50 percent by 2030.
SB 350 put this goal into law.
While implementing the 50 percent renewable requirement, care must be taken to maintain
the reliability of the electricity system and keep costs competitive. As prices for photovoltaic
systems continue to drop, use of these systems has grown tremendously in recent years and
account for more than 90 percent of the renewable installations expected through 2016. The
increased deployment of photovoltaics is a success story, but it also poses challenges. Given
2

the intermittent nature of photovoltaic systems, integrating the energy into the grid is a key
challenge moving toward the 50 percent renewable goal. One key solution is a regional
marketplace that balances supply and demand. SB 350 paves the way for the voluntary
transformation of the California Independent System Operator into a regional organization
that will help integrate renewable generation for greater reductions in greenhouse gas
emissions in California and neighboring states and at lower cost. Other solutions include
targeted energy efficiency, demand response, time-of-use rates that encourage shifts in
when consumers use energy, a more diversified portfolio of renewable resources, and
storage. Finally, research and development will help bring new technologies and other
innovations needed to meet the 2030 and 2050 greenhouse gas reduction goals.
Strategic Transmission Investment Planning
Geographic diversity in the renewables portfolio can help achieve the 50 percent renewable
goal by 2030. Strategic transmission investments are needed to link our extensive renewable
resources to load centers throughout the grid. Transmission planning processes will need to
be streamlined and coordinated to ensure the siting, permitting, and construction of the
most appropriate transmission projects takes proper consideration of renewable energy
potential, land-use, and environmental factors.
Lessons from the Renewable Energy Transmission Initiative, the Desert Renewable Energy
Conservation Plan, local planning efforts, other energy planning processes, and scientific
studies have brought important insights to the environmental and operational implications
of the evolving regional electricity system. To plan for meeting California’s 2030 climate and
renewable energy goals, the Energy Commission, California Public Utilities Commission,
and the California Independent System Operator have initiated the Renewable Energy
Transmission Initiative 2.0 process to consider the relative potential of various renewable
energy resources and to explore the associated transmission infrastructure through an open
and transparent stakeholder process.
Transformation to a Low-Carbon Transportation System Is Needed
California has long been a leader in transportation policy and moving to a low-carbon
transportation system is an important part of the state’s efforts to meet the 2030 greenhouse
gas reduction goal. The transportation sector represents the state’s largest source of
greenhouse gas emissions, accounting for 37 percent of California’s emissions profile.
Furthermore, it is the largest source of criteria air pollutants that are harmful to human
health, especially in the most impacted areas of the state. To help address these issues, the
state has developed a portfolio of goals, policies, and strategies designed to reduce GHG
emissions, improve air quality, and reduce petroleum use while meeting the transportation
demands of the future.
Governor Brown called for a 50 percent reduction in petroleum used by California’s cars
and trucks by 2030 in his 2015 inaugural address. The Governor has released several
executive orders easing the transition to a low-carbon transportation future. These include
calling for 1.5 million zero-emission vehicles to be on California roadways by 2025 and for
3

the development of an integrated action plan that establishes targets to improve freight
efficiency, increases adoption of zero-emission technologies, and increases competitiveness
of California’s freight system. As a result of these goals and policies, the state has
implemented a number of programs and plans to put California on a path to a diversified
alternative and low-carbon fueled transportation future, including the zero-emission vehicle
mandate, the Low Carbon Fuel Standard, and the Cap-and-Trade Program. The Energy
Commission’s Alternative and Renewable Fuel and Vehicle Technology Program also plays
a role in the state strategy to deploy alternative fuels and advanced vehicle technologies into
California’s transportation market.
The Energy Commission staff has also developed a preliminary transportation energy
demand forecast through 2026 to help inform policy makers. The preliminary results show
that given the information available today, gasoline and diesel will continue to be the
primary sources of transportation fuel through 2026. Long-term transformation of the
transportation system is achievable but will require efforts on many fronts with a diverse
range of actors and partnerships.
Preliminary 10-Year Electricity Forecast Shows Low Growth
Developing a 10-year forecast of electricity consumption and peak electricity demand is a
fundamental part of statewide electricity infrastructure planning. The Energy Commission,
California Public Utilities Commission, and California Independent System Operator are
continuing their commitment to consistently use a single forecast set in each of their
planning processes, as first implemented through the 2013 Integrated Energy Policy Report
(IEPR). SB 350, by calling on the Energy Commission to set statewide targets for energy
efficiency savings, will require the Energy Commission to build its capabilities to collect and
manage increasing quantities of data and provide rigorous analysis in support of energy
demand forecasts specifically and energy policy development more broadly. This leadership
is more important now than ever, given that California will be pushing the envelope on
various fronts and focusing resources on innovation and market support in the years ahead.
The 2015 preliminary forecast recognizes the importance of energy efficiency and includes
estimated energy efficiency impacts from energy efficiency programs administered by
investor- and publicly owned utilities. The final version will also include projected
Additional Achievable Energy Efficiency savings for both investor- and publicly owned utilities
to develop a managed forecast for planning purposes. Consistent with the 2013 IEPR and 2014
IEPR Update, the 2015 preliminary forecast incorporates anticipated changes in demand due
to climate change based on analysis by the Scripps Institution of Oceanography. The 2015
preliminary forecast also includes projected demand from electric vehicles. The electric
vehicle forecast will be revised in the final version to incorporate new survey data.
The 2015 preliminary forecast results show slightly lower growth for electricity
consumption compared to the forecast from the 2014 IEPR Update. Annual growth in
consumption from 2016−2026 for the preliminary forecast averages 1.45 percent, 1.20
percent, and 1.01 percent in the high, mid, and low cases, respectively, compared to 1.23
4

percent in the 2014 IEPR Update mid case. Higher projections for self-generation,
particularly photovoltaic systems, reduce growth in peak demand and retail sales. Annual
growth rates for peak demand for the preliminary forecast average 1.20 percent, 0.89
percent, and 0.52 percent in the high, mid, and low scenarios, respectively, compared to 1.13
percent in the 2014 IEPR Update mid case. For sales, annual growth averages 1.01 percent,
0.68 percent, and 0.42 percent in the high, mid, and low cases, respectively, versus 1.06
percent in the 2014 IEPR Update mid case.
Natural Gas
While natural gas may provide a lower carbon fuel source when compared to other fossil
fuels used for electricity generation or transportation, recent studies indicate that methane
leakage can reduce the climate benefits of switching to natural gas. Many research efforts
are aimed at better understanding the leakage rates and these tradeoffs. Converting biomass
to renewable natural gas for use in the transportation sector, electricity generation, and enduse
consumption reduces the climate impacts of this fuel, but resource availability may be
limited. Protecting public safety remains an important focus in managing the natural gas
system.
Assembly Bill 1257 (Bocanegra, Chapter 749, Statutes of 2013) directs the Energy
Commission to explore the strategies and options for using natural gas, including biogas, to
identify strategies to maximize its benefits. Highlights of the Energy Commission staff’s
analysis are presented on topics that include pipeline safety, renewable integration,
combined heat and power, natural gas as a transportation fuel, end-use efficiency, lowemission
biomethane, and greenhouse gas emissions associated with leakage from the
natural gas system.
Similar to electricity, the Energy Commission develops a forecast of natural gas prices,
production, and demand as detailed in the 2015 Natural Gas Outlook. The preliminary
forecast for end-use natural gas demand shows about 11 percent higher growth rate than
the 2013 IEPR forecast. Staff attributes the higher growth rates to an increase in natural gas
demand for transportation (with heavy-duty trucks having a large increase over the forecast
period), followed by an increase in residential demand. Demand for natural gas used in
electricity generation, however, is expected to decline over the forecast period. This is
driven by increases in the share of electricity generated from renewable resources that
reduce the need for power from fossil-fueled sources.
Nuclear Issues in California
On June 27, 2013, Southern California Edison announced it had decided to permanently
retire the San Onofre Units 2 and 3. The decommissioning of a nuclear power plant involves
transferring used fuel into safe storage and removing and disposing of radioactive
components and materials. While the Nuclear Regulatory Commission allows up to 60 years
to complete the decommissioning, Southern California Edison plans to complete the process
within 20 years. In the 2013 IEPR, the Energy Commission recommended Southern
5

California Edison transfer its spent fuel from pools into dry casks; the transfer of spent fuel
into dry casks is expected to be complete by 2019.
The Diablo Canyon Power Plant operates under its original licenses, which are set to expire
in 2024 and 2025, respectively. While Pacific Gas and Electric filed an application with the
Nuclear Regulatory Commission in 2009 to renew its operating license, it is uncertain
whether Diablo Canyon will continue to operate beyond its current licensed period. One
factor impacting the future of Diablo Canyon is the costs associated with compliance with
the State Water Resources Control Board’s once-through-cooling policy, which establishes
uniform standards to reduce the harmful effects associated with cooling water intake
structures on marine life. Estimates of total project costs for possible solutions range as high
as $14 billion and could take as long as 14 years to complete. Another factor influencing
Diablo Canyon’s license renewal application is the seismic study recommended by the
Energy Commission in its 2013 IEPR. Pacific Gas and Electric completed its study in
September 2014 and concluded that its plant is designed to withstand a major earthquake on
any of the faults surrounding Diablo Canyon.
While the initial pact between nuclear power plant operators and the federal government
arranged for the federal government to remove spent nuclear fuel from the plants for
reprocessing or disposal at a federally managed site, that plan has not come to fruition. The
proposal to create a waste depository at Yucca Mountain in Nevada was recently
abandoned, leaving California to face a prolonged period of maintaining spent nuclear fuel
at decommissioned plant sites. Proposed federal legislation would authorize the U.S.
Department of Energy to move forward with developing an interim storage facility and
provide financial benefits to communities that agree to host such a facility.
Ongoing Vigilance to Maintain Reliability in Southern California
With the impending retirement of several fossil-powered facilities and the closure of the San
Onofre Nuclear Generating Station in Southern California, ensuring the region’s electricity
system reliability has been a major focus since 2011. The State Water Resources Control
Board’s 2010 policy to phase out the use of once-through cooling affects 10 power plants in
the Los Angeles and San Diego basins. Those power plants total just over 11,000 megawatts;
taken into consideration along with the 2,200 megawatts lost with the 2013 closure of San
Onofre, it is important to ensure that the region does not suffer grid reliability issues.
Shortly after the announced closure of San Onofre, Governor Brown asked for a multiagency
plan to address the replacement of the power and energy that had been provided by
the plant. As reported in the 2013 IEPR, this effort resulted in the Preliminary Reliability Plan
for LA Basin and San Diego. The plan called for a rough replacement target of 50 percent
preferred resources and 50 percent conventional generation. Since the release of the plan, an
interagency team has continued to meet regularly. The 2014 IEPR Update covered the
progress made since the formation of the team, and this year’s report covers the additional
work completed to date on local capacity issues, resource procurement, contingency
planning, and mitigation options, as well as the work that will be needed going forward.
6

Trends in Crude Oil Production and Transport
Due largely to advances in drilling techniques, U.S. oil production reached 9.7 million
barrels per day in April 2015—the highest level of production since April 1971. This
increased production led to increased supply, which led to lower crude oil prices. Excessive
supply weighed heavily on world markets, leading to a pricing collapse that began in mid-
2014 and has continued through the third quarter of 2015.
As outlined in the 2014 IEPR Update, this large increase in crude oil production surpassed
the ability of existing crude oil pipeline and distribution infrastructure to keep pace. Oil
producers discounted their oil prices to allow the more expensive transportation of oil by
rail to be competitive for refiners outside the shale oil regions. Over the last 18 months,
however, additional pipeline capacity has come on-line and reduced the need for ongoing
price discounts from oil producers. Whether crude-by-rail imports to California will
continue rising over the next few years depends on the number of receiving facilities that
are ultimately approved and built within the state.
There have been several safety-related regulation updates since the 2014 IEPR Update. Most
notably, regulations finalized in May 2015 by the Pipeline and Hazardous Materials Safety
Administration place slower speed restrictions on trains transporting oil or ethanol. By 2021,
these trains will also need to be equipped with electronically controlled pneumatic braking.
In addition to improved braking and reduced operating speeds, rail cars transporting oil or
ethanol are now also subject to more stringent construction standards.
The recent decline of crude-by-rail shipments, following rapid increases in 2014, along with
a lack of detailed forecasts and the wide range of crude oil carbon intensities, further
highlights the need for additional data at the state level to follow oil extraction,
transportation, and distribution trends, and determine resulting implications.
California’s Response to Drought
California is suffering from one of the worst droughts on record, and the inextricable
linkages between water and energy are becoming more evident. California’s climate is
shifting toward warmer winters with less snowpack, affecting the availability and timing of
hydropower. Further, water delivery is very energy-intensive, and so implementing water
conservation programs can reduce greenhouse gas emissions in the electricity sector by
reducing the need for energy to move, treat, and heat water. The drought also raises
questions about the reliability of water supply for natural gas, solar thermal, and
geothermal power plants that use water in electricity generation.
The drought is not a short-term problem. As the climate continues to change, California
must prepare for the possibility that these drought-like conditions may become the norm
rather than the exception. In response, the state is enacting many programs to help with
long-term water savings on a wide variety of fronts. For example, through the Energy
Commission’s appliance standards regulation, the state is advancing efficiency
improvements in appliances such as toilets and showers. Consumer rebates and direct
installation projects for other water-efficient appliances are also being developed and
7

implemented by the Energy Commission and the Department of Water Resources. Finally, a
larger-scale effort is the Water Energy Technology program, administered by the Energy
Commission, to fund for innovative water- and energy-saving technologies and reduce
greenhouse gas emissions. Advancing conservation programs like these can both help make
California more drought resilient, and at the same time reduce energy use and greenhouse
gas emissions.
Climate Change Research
The Energy Commission continues to be a leader in supporting and conducting cuttingedge
climate research related to energy sector resilience (successfully adapting to climate
change) and mitigation (reducing greenhouse gas emissions).
Impacts to California’s energy system from climate change include decreased efficiency of
thermal power plants and substations; decreased capacity of transmission lines; risks to
energy infrastructure from extreme events including sea level rise, coastal flooding, and
wildfires; less reliable hydropower resources; and increased peak electricity demand. The
types and severity of impacts vary across the electricity, natural gas, and petroleum sectors
and vary geographically. Over the past several years, the Energy Commission has
supported research to identify these potential impacts and investigate the magnitude,
distribution, and adaptation options. To date, significantly more research has been done on
electricity than other aspects of the energy sector like natural gas or the petroleum sector,
but even for the electricity sector, more research is needed on the impacts to renewable
resources such as solar and wind.
Areas for future research include the development of improved climate and sea-level-rise
scenarios for the energy system, improved methods to estimate greenhouse gas emissions
originating from the energy system, development of advanced methods to simultaneously
consider mitigation and adaptation for the energy system, and detailed local and regional
studies.
8

Introduction
Addressing Climate Change is the Foundation of California’s
Energy Policy
On April 29, 2015, Governor Edmund G. Brown Jr. established a new statewide greenhouse
gas (GHG) emissions reduction goal to reduce emissions 40 percent below 1990 levels by
2030. 1 This order strengthens the state’s position to meet its 2050 goal of reducing GHG
emissions 80 percent below 1990 levels. 2 The 2030 goal also builds on the mandatory target
set forward in California’s Global Warming Solutions Act of 2006 (Assembly Bill 32, Núñez,
Chapter 488, Statutes of 2006) to achieve 1990 emission levels by 2020. The state is well on its
way to meeting its 2020 target. 3 Figure 1 plots California’s GHG reduction goals against
historical GHG emissions.
Figure 1: California's GHG Emission Reduction Goals
Source: Air Resources Board 2000-2013 inventory http://www.arb.ca.gov/cc/inventory/data/data.htm
1 Executive Order B-30-15, http://gov.ca.gov/news.php?id=18938.
2 California's 2050 climate goal was reiterated in B-30-2015 and previously put forward in in
Executive Orders S-3-05 http://gov.ca.gov/news.php?id=1861 and B-16-2012
http://gov.ca.gov/news.php?id=17472.
3 California Air Resources Board, The First Update to the Climate Change Scoping Plan, Building on the
Framework, May 2014,
http://www.arb.ca.gov/cc/scopingplan/2013_update/first_update_climate_change_scoping_plan.pdf.
9

Californians are feeling the effects of climate change in more extreme fires, storms, floods,
and heat waves that cost lives and property damage. (For further discussion, see Chapter 9
Climate Change, Vulnerability and Adaptation Options). The potential human, ecological,
and economic costs of climate change are large, but measures to adapt to these changes can
reduce overall economic costs. 4 California must continue its leadership to both reduce GHG
emissions and increase its resilience to climate change.
In his inaugural address, on January 5, 2015, Governor Brown said, “Taking significant
amounts of carbon out of our economy without harming its vibrancy is exactly the sort of
challenge at which California excels. This is exciting, it is bold, and it is absolutely necessary
if we are to have any chance of stopping potentially catastrophic changes to our climate
system.”
The Governor identified major areas of the California economy that must reduce emissions
to meet the 2030 goal. 5 He set the following subgoals, or five “pillars,” for reducing
emissions:
1. Reduce today's petroleum use in cars and trucks by up to 50 percent.
2. Increase from one-third to 50 percent California’s electricity derived from renewable
sources.
3. Double the efficiency savings achieved at existing buildings and make heating fuels
cleaner.
4. Reduce the release of methane, black carbon, and other short-lived climate
pollutants.
5. Manage farm and rangelands, forests, and wetlands so they can store carbon.
In early July 2015, the Governor’s office and relevant state agencies and boards held a series
of public forums soliciting stakeholder input on each of the pillars listed above. Some
highlights from the energy-related discussions at the public forums are included in the
chapters that follow.
4 Karhrl, Fredrich, and Roland-Holst, David. 2012. Climate Change in California. Risks and Response.
University of California Pres.
From Boom to Bust? Climate Risk in the Golden State. April 2015. A product of the Risky Business Project
http://riskybusiness.org/uploads/files/California-Report-WEB-3-30-15.pdf.
5 Governor Brown’s inaugural address, January 5, 2015, http://gov.ca.gov/news.php?id=18828.
10

Energy Efficiency as a Focus of This Integrated Energy Policy
Report
As California develops strategies to meet its goals for deep GHG emissions reductions,
energy efficiency will be a central component (for further discussion, see Chapter 1.) At
sufficient scale, energy efficiency can reduce the need for new generation—both fossil and
renewable—while increasing system flexibility and lowering costs. Thus, energy efficiency,
especially when integrated with demand response, can greatly ease the transition to a
cleaner resource mix—a need accelerated by the retirement of the San Onofre Nuclear
Generating Station and the impending retirement of the aging, once- through-cooled coastal
generation fleet.
In particular, improving the energy efficiency of existing buildings, and the appliances and
other devices within them, will be critical toward achieving California’s GHG reduction
goals. In his January 2015 inaugural address, Governor Brown identified a goal of doubling
the efficiency of existing buildings and making heating fuels cleaner. Energy use at existing
buildings accounts for more than one-quarter of all GHG emissions in California, including
both fossil fuel consumed on-site (for example, gas or propane for heating) and emissions
associated with electricity consumed in existing buildings (for example, for lighting,
appliances, and cooling). Assembly Bill 758, (AB 758, Skinner, Chapter 470, Statutes of 2009)
recognized the need for California to address climate change through reduced energy
consumption in existing buildings and directed the Energy Commission to develop a plan to
achieve cost-effective energy savings in California’s existing residential and nonresidential
buildings, and to report on its implementation through the Integrated Energy Policy Report
(IEPR). The Energy Commission adopted the final Existing Buildings Energy Efficiency Action
Plan in September 2015. Strategies in the action plan provide a 10-year framework to enable
substantial energy savings and GHG emission reductions in California’s existing buildings.
The Existing Buildings Energy Efficiency Action Plan dovetails nicely with the Governor’s
energy efficiency goal, and together they provide impetus and urgency.
Energy efficiency has additional benefits beyond climate—economic activity and resilience,
local determination, health and air quality comfort—which further validate its primacy
among clean energy options.
GHG Emission Sources
California’s GHG emissions are primarily carbon dioxide from the combustion of fossil
fuels. For the IEPR, the energy system is defined as including all activities related to energy
extraction (for example, oil and natural gas wells), fuel and energy transport (for example,
oil and natural gas pipelines), conversion of one form of energy to another (such as
producing gasoline and diesel from crude oil in refineries and combusting natural gas in
11

power plants to generate electricity), and energy services (such as electricity for lighting,
natural gas use in homes and buildings for space and water heating, and gasoline and diesel
use in cars and trucks). 6 Under this broad definition, the energy system was responsible for
about 80 percent of the gross 7 GHG emissions in 2013. This includes GHG emissions
associated with out-of-state power plants providing electricity consumed in California.
Figure 2 shows GHG emissions by sector of the economy, including electricity sector
emissions, broken down by end use. California’s transportation sector is the largest source
of GHG emissions in California, accounting for 37.4 percent of the state’s GHG emissions.
By comparison, electricity generation accounts for about 20 percent of the state’s GHG
emissions (not shown as a discrete category in Figure 2). Close to half of electricity
emissions are from out-of-state power consumed in California. Emissions from the
industrial sector (26.5 percent) include emissions associated with oil refineries (also not
shown). Emissions from the residential and commercial sectors account for 26.6 percent of
emissions. Figure 2 includes energy and non-energy-related emissions from the agricultural
and industrial sectors. 8
Figure 2: California’s GHG Emissions by Sector
(Million Metric Tonnes of CO 2 Equivalent- MMTCO 2 e)
Source: Air Resources Board, GHG Emission Inventory – 2015 Edition. http://www.arb.ca.gov/cc/inventory/data/data.htm and
data from Energy Commission staff. Emissions from the electricity sector are broken down based on energy consumption data
for 2013.
6 California Energy Commission. 2013. 2013 Integrated Energy Policy Report. Publication Number:
CEC-100-2013-001-CM.
7 The ARB GHG inventory also reports GHG sinks (for example, increased carbon stored in forests),
but the sinks are relatively minor. For this reason, total net emissions are very close to total gross
GHG emissions.
8 Examples of non-energy-related GHG emissions from these sectors include nitrous oxide from
nitrogen-based fertilizers and carbon dioxide from the production of cement.
12

Guiding Principles for Reducing GHG Emissions
In his April 29, 2015, Executive Order (B-30-15), Governor Brown outlined that going
forward state agencies’ planning and investment should be guided by four principles. 9
These guiding principles include the following:
• Give priority to actions that both build climate preparedness and reduce GHG emissions. For
example, adding insulation to buildings both improves occupant comfort in hot
weather and reduces the need for air conditioning, which also reduces GHG
emissions.
• Use adaptive and flexible approaches where possible to prepare for uncertain climate impacts.
A useful and easily accessible resource to identify potential climate change impacts
is Cal-Adapt, a web-based climate adaptation planning tool. Using data compiled on
an ongoing basis from California’s scientific and research community, it allows users
to see possible effects on temperature change, snowpack, precipitation, fire risk, and
sea level rise downscaled to California’s geography.
• Act to protect the state’s most vulnerable populations. Senate Bill 535 (De León, Chapter
830, Statutes of 2012) requires investments in California’s most burdened
communities to help improve public health, quality of life, and economic
opportunity while reducing GHG emissions. The California Environmental
Protection Agency identified disadvantaged communities using the California
Communities Environmental Health Screening Tool (CalEnviroScreen) to identify
the areas disproportionately burdened by and vulnerable to multiple sources of
pollution.
• Prioritize natural infrastructure solutions. An example is to prioritize protecting natural
wetlands to provide needed habitat and other benefits such as flood protection over
developing walls to block storm surges.
Drought is another key consideration in the energy sector. As California continues to suffer
from one of the worst droughts on record and its climate shifts toward warmer winters with
less snowpack, water conservation and management have become increasingly important. 10
Water and energy are inextricably linked, and efforts to better manage each resource can be
mutually beneficial. The linkage is probably most readily apparent in the availability of
hydropower: reduced snowpack affects the availability and timing of hydropower. Further,
water delivery is energy-intensive, so water conservation programs can reduce GHG
9 http://gov.ca.gov/news.php?id=18938.
10 In January 2014, Governor Brown declared a Drought State of Emergency. In May 2015, he put
forward mandatory, statewide water cuts for the first time in the state’s history, Executive Order B-
29-15, http://gov.ca.gov/news.php?id=18910.
13

emissions in the electricity sector by reducing the need for energy to move, treat, and heat it.
The drought also raises questions about the reliability of water supply for natural gas, solar
thermal, and geothermal power plants that require it for process use. The nexus between
water and energy use is discussed in more detail in Chapter 8.
Air quality will be another driver of energy policy and an important consideration in efforts
to reduce GHG emissions. To meet federal health-based air quality standards the San
Joaquin Valley and South Coast air basins could be required to cut oxides of nitrogen
emissions up to 80 percent from current regulatory levels between 2023 and 2032. A key
measure to meet these air quality standards is electrification of the transportation sector
which, coupled with increased renewables in the electricity sector, is critical to meeting
GHG reduction goals. Recent research shows, however, that the largest sources of criteria
pollutants such as oxides of nitrogen, in the South Coast Air Basin are not necessarily the
most important sources of GHGs, so reductions in air pollution may not be proportional to
GHG reductions, and vice versa. This conclusion highlights the need for vigilance in
achieving both climate and air quality goals. 11
California’s Leadership in Addressing Climate Change
In issuing Executive Order B-30-15 to reduce GHG emissions 40 percent by 2030, the
Governor not only set a bold policy for California, but also provided an example for other
nations and sub-national bodies. The United Nations Framework Convention on Climate
Change Executive Secretary Christiana Figueres said, "California's announcement is a
realization and a determination that will gladly resonate with other inspiring actions within
the United States and around the globe. It is yet another reason for optimism in advance of
the UN climate conference in Paris in December."
In May 2013, the Governor joined more than 500 world-renowned researchers and scientists
in releasing a call to action on climate change. 12 The “consensus document” translates key
scientific climate findings on climate change and other threats to humanity into one 20-page
document that aims to help bridge scientific research and policy. This document informed
development of the Governor’s climate change policy.
Achieving deep GHG emission reductions will require unprecedented levels of coordination
with business, the private sector, and local, state, and federal government. For example, on
August 3, 2015, President Obama and the U.S. Environmental Protection Agency announced
11 Joint Agency Workshop on Climate Adaptation Opportunities for the Energy Sector, July 27, 2015,
http://www.energy.ca.gov/2015_energypolicy/documents/2015-07-27_cpuc_presentations.php.
12 Scientific Consensus on Maintaining Humanity’s Life Support Systems in the 21st Century: Information
for Policy Makers. May 21, 2013. http://mahb.stanford.edu/consensus-statement-from-global-
%20scientists.
14

the Clean Power Plan to help reduce carbon pollution from power plants nationwide. 13 The
Clean Power Plan sets carbon pollution reduction goals for the power sector at 32 percent
below 2005 levels by 2030, and emissions of sulfur dioxide from power plants 90 percent
lower. 14 In a statement made the same day, Energy Commission Chair Robert B.
Weisenmiller said, “California is a strong supporter of this commonsense plan to cut carbon
pollution from power plants and will continue to lead the way in reducing greenhouse gas
emissions.” 15
California is working on multiple geographic and administrative levels to create and
implement a coherent strategy that reduces GHG emissions and minimizes vulnerabilities to
ongoing and future climate changes. The California Air Resources Board is embarking upon
a second update to the scoping plan to reduce GHG emissions. The Natural Resources
Agency will update its state climate adaptation strategy, Safeguarding California, every
three years. The Energy Commission is leading the preparation of this plan for the energy
sector in cooperation with the CPUC and the Department of General Services. State agencies
are implementing the Climate Action Team Climate Change Research Plan for California, 16
which is designed to promote fast and efficient GHG reduction while bolstering adaptive
capabilities across California.
Governor Brown has signed accords to fight climate change with leaders from Mexico,
China, Canada, Japan, Israel, and Peru. On May 19, 2015, Governor Brown signed the Under
2 MOU, an agreement with international leaders from 11 other states and provinces 17 to
limit the increase in global average temperature to below 2 degrees Celsius (3.6 degrees
Fahrenheit), the upper boundary of global temperature rise suggested by the
Intergovernmental Panel on Climate Change for avoiding catastrophic climate change. 18
Since the initial signing, six additional states and provinces have joined the agreement.
13 https://www.whitehouse.gov/the-press-office/2015/08/03/fact-sheet-president-obama-announcehistoric-carbon-pollution-standards.
14 http://www.epa.gov/airquality/cpp/fs-cpp-overview.pdf.
15 http://www.energy.ca.gov/releases/2015_releases/2015-08-
03_Weisenmiller_statement_re_clean_power_nr.html.
16 http://www.climatechange.ca.gov/climate_action_team/reports/CAT_research_plan_2015.pdf.
17 The signatories include California, USA; Acre, Brazil; Baden-Württemberg, Germany; Baja
California, Mexico; Catalonia, Spain; Jalisco, Mexico; Ontario, Canada; British Columbia, Canada;
Oregon, USA; Vermont, USA; Washington, USA; and Wales, UK. The Mexican state of Chiapas and
Cross River State in Nigeria joined in June and the Rhône-Alpes region in France, Scotland, Spain’s
Basque Country and Quebec joined in July 2015.
18 New, Mark, Diana Liverman, Heike Schoder, and Kevin Anderson. 2011. “Four Degrees and
Beyond: The Potential for a Global Temperature Increase of Four Degrees and Its Implications.” Phil.
Trans. R. Soc. A 363: 6-19.
15

Signatories commit to either reduce GHG emissions 80 to 95 percent below 1990 levels by
2050 or achieve a per capita annual emission target of less than 2 metric tons by 2050.
The “Under 2 MOU” provides a template for nations worldwide. The MOU will enhance
cooperation by developing targets to support long-term reduction goals, sharing best
practices to promote energy efficiency and renewable energy, working together to increase
the use of zero-emission vehicles, ensuring consistent monitoring and reporting of GHG
emissions, reducing short-lived climate pollutants to improve air quality, and calculating
the anticipated impacts of climate change on communities. 19
Reducing GHG emissions is the challenge of today and for the next several decades. The
policies put forward in this report aim to help California achieve its 2030 and 2050 GHG
reduction goals.
19 http://gov.ca.gov/news.php?id=18964.
16

CHAPTER 1:
Energy Efficiency
California has long been a leader in advancing building energy efficiency. Over the last 40
years California has implemented cost-effective building codes and appliance standards that
have saved consumers billions of dollars. A variety of ratepayer-funded programs, from
financial assistance to workforce education and public outreach, are helping businesses and
homes reduce energy costs and carbon emissions. Efficiency is also reducing California’s
energy infrastructure costs by easing the energy demand that must be met by either fossil or
renewable generation. Within the electricity sector, efficiency can reduce infrastructure
needs and lower renewable electricity procurement requirements, and similarly allow
greater electric infrastructure flexibility as the state moves toward electrified transportation.
Past successes in energy efficiency have helped limit electricity consumption growth to
roughly one percent annually, and natural gas consumption growth to nearly zero. (See
Chapters 5 and 6, respectively, for recent trends in electricity and natural gas consumption.)
But California needs to significantly increase levels of energy efficiency in buildings to meet
its aggressive greenhouse gas (GHG) emission reduction goals. Commercial and residential
buildings account for nearly 70 percent of California's electricity consumption and 55
percent of its natural gas consumption. New efforts must activate efficiency markets that
truly compete with other energy supplies. A clear focus on the existing building stock, with
its great potential to reduce current levels of energy usage, is warranted.
This chapter discusses the Energy Commission’s efforts to improve the energy efficiency of
the existing building stock. The chapter also discusses progress by the investor- and publicly
owned utilities in meeting their energy efficiency goals, progress in implementing the Clean
Energy Jobs Program, created through enactment of Proposition 39, and progress in
advancing the state’s zero-net-energy goals.
Existing Building Energy Efficiency
Assembly Bill 758 (Skinner, Chapter 470, Statutes of 2009) recognized the need for California
to address climate change through reduced energy consumption in existing buildings. As
part of his January 2015 Inaugural Address, Governor Edmund G Brown Jr. included a
GHG reduction goal to double the expected energy efficiency savings from existing
buildings.
Senate Bill 350 (De León, 2015) codified and built on the Governor’s goal. The bill included
provisions that will, among others things, set a similar goal of doubling energy efficiency
savings by 2030, require the Energy Commission (in collaboration with the CPUC) to
establish annual targets toward the 2030 goal, and report progress every two years starting
with the 2019 IEPR. The bill also requires the CPUC to revisit its rules governing energy
efficiency programs, both to authorize a broader array of program types and to tie incentive
payments to measurable efficiency results. Where feasible and cost effective, the bill requires
17

that energy efficiency savings be measured with consideration toward the overall reduction
in normalized metered electricity and natural gas consumption. The bill also requires the
Energy Commission to update its Existing Building Energy Efficiency Action Plan every three
years. All of these activities will require more detailed, localized, and sector-specific
analyses of energy efficiency and demand in the future. Potential impacts from the bill on
the Energy Commission’s electricity demand forecasting are discussed further in Chapter 5.
Most existing buildings have cost-effective opportunities for improving their energy
performance. About half of the existing buildings were built before the state’s building
design and construction standards included any energy efficiency requirements. An
illustration of the age of residential buildings in the state can be seen in Figure 3. In the last
decade California’s building standards have required high levels of efficiency, such that
older buildings that were once upgraded and buildings built to code five or more years ago
also have significant energy savings potential.
Figure 3: Single- and Multi-family Homes by Decade of Construction
Source: California Energy Commission. Includes estimates of future construction through 2020.
Doubling the rate of energy savings from existing building efficiency improvement projects
would result in lower total building energy use in 2030 than in 2014, despite significant
population and economic growth, and is equivalent to a 20 percent reduction in usage
compared to projected 2030 levels. The Existing Buildings Energy Efficiency Action Plan,
adopted by the Energy Commission in September 2015, introduces strategies to set
California on a path to achieve this goal. The plan articulates the vision of robust and
sustainable efficiency markets that deliver multiple benefits to building owners and
occupants through physical and operational improvements to existing homes, businesses,
18

and public buildings.
The plan describes five discrete goals and delineates multiple strategies to achieve each
goal. The plan goals are:
1. Increased government leadership in energy efficiency.
2. Data-driven decision making.
3. Increased building industry innovation and performance.
4. Recognized value of energy efficiency.
5. Affordable and accessible energy efficiency solutions.
Within each of these goals are multiple strategies, each with responsible entities and time
frames identified. Figure 4 outlines the overall implementation schedule for the strategies
that constitute the five goals.
19

Figure 4: Existing Buildings Energy Efficiency Action Plan Implementation Schedule
Source: Energy Commission, Existing Buildings Energy Efficiency Action Plan.
Improving the energy efficiency of existing buildings, and the appliances within, will be a
key part of achieving California’s ambitious GHG reduction goals given that California’s
building stock accounts for more than one-quarter of GHG emissions statewide. In 2013 (the
most recent year data are available) residential and commercial end uses each accounted for
13.3 percent of statewide GHG emissions. This includes both fossil fuel consumption on-site
20

(for example, gas or propane for heating), as well as upstream emissions from electricity
that served those sectors. 20
The 40 percent GHG reduction target established by Governor Brown’s Executive Order B-
13-05 cannot be met within the building sector unless private capital and market forces are
brought to bear; current ratepayer- and taxpayer-funded efficiency efforts will not be
sufficient on their own. Private capital in the range of $10 billion annually will need to be
invested in California's existing building stock. Efficiency can and should compete with
other energy supply resources, enabling it to do so requires resolving the significant
transaction costs and information vacuums that constrain the efficiency market.
Figure 5 shows the approximate reduction in building energy consumption per capita that
will be necessary to double energy efficiency savings. The purple line atop the chart
assumes achievement of energy efficiency from adopted and funded policies, standards,
and programs (also known as “committed savings”). The orange wedge represents savings
projected to occur via planned California and national appliance efficiency standards,
increasing building energy efficiency standards through 2022, and continuous
implementation of ratepayer-funded energy efficiency programs. The blue wedge
represents a doubling thereof, achieved in part by efficiency savings from investments and
behavioral changes made by consumers and businesses outside of incentive programs. This
is likely to require both new efforts and revised approaches to encouraging energy
efficiency gains.
Figure 5: Reduced Energy Consumption by Doubling Energy Efficiency
Source: Energy Commission, Existing Buildings Energy Efficiency Action Plan.
20 GHG Emission Inventory – 2015 Edition. Air Resources Board.
http://www.arb.ca.gov/cc/inventory/data/data.htm. Data from Energy Commission staff. Emissions
from the electricity sector are disaggregated based on energy consumption data for 2013.
21

As part of developing the 2015 IEPR, the Energy Commission held multiple workshops to
present staff information and receive comments from state and federal agencies, private
stakeholders, and the public. Participants discussed issues and opportunities on the overall
approach toward meeting the Governor’s goal to double the expected energy efficiency
savings from existing buildings, as well as select plan goals and strategies. Workshop topics
included an introduction to the plan in general, improved data access, energy benchmarking
for buildings, local government leadership, zero-net-energy buildings, plug-load efficiency,
and building efficiency standards as they apply to existing buildings. 21
Local Government Leadership
Local governments have unique connections to their constituents and can effectively
implement both voluntary and mandatory programs to increase existing building energy
efficiency, not only in their own government buildings but in the residential and
commercial buildings in their communities. However, one of the major challenges for many
local governments is the lack of consistent funding sources for sustainability activities. The
plan includes the recommendation that the Energy Commission modify funding efforts
from the American Recovery and Reinvestment Act (local government) to improve their
effectiveness and expand their impact. The Energy Commission would allocate $11 million
of remaining American Recovery and Reinvestment Act funds to award innovative local
governments contemplating efficiency initiatives that promise to enable greater flow of
energy efficiency projects in their jurisdictions and beyond. The opportunities for local
governments to engage their constituents to improve building energy efficiency far exceed
this funding amount, and the Energy Commission will seek to supplement this grant
program, building on its success.
Data for Informed Decisions
Data access is critical to increase the scale of energy efficiency upgrades in California
buildings. The building energy efficiency market cannot thrive without informed decision
makers. Every part of the market, from building owners and occupants to contractors,
product manufacturers, and investors needs access to data on actual efficiency upgrade
costs and savings. Experience has shown that modeled estimates will not suffice.
Knowledge of realized costs and measured savings reduce perceived risks. There is very
little public information on typical equipment replacement costs or actual energy savings
from efficiency upgrades. Consumers hesitate to invest in energy efficiency improvements
in part because they lack the information needed to understand these investments in
concrete terms.
21 All workshop notices, agendas, presentations, transcripts, and written comments from the 2015
IEPR’s previous energy efficiency workshops are available online at
https://efiling.energy.ca.gov/Lists/DocketLog.aspx?docketnumber=15-IEPR-05.
22

For example, the California Solar Initiative produced a public database of all photovoltaic
(PV) systems installed in California that received a public incentive under the California
Solar Initiative. This includes data on system costs, rebate amount, system size, zip code,
installing contractor, project completion time, equipment brand, and other important data
for more than 150,000 units. As rebates have been exhausted for much of the California Solar
Initiative, the database will also be populated with investor-owned utilities’ net energy
metering 22 interconnection data per direction by the California Public Utilities Commission.
This database is a valuable source of information to both the photovoltaic (PV) industry and
the public. Figure 6 highlights some of the many statistics available on the California Solar
Statistics website with California Solar Initiative data and investor-owned utilities’ net
energy metering interconnection data. 23
Figure 6: Screenshot from California Solar Statistics Website
Source: Go Solar California, www.californiasolarstatistics.ca.gov/. As of August 4, 2015, new data from net energy
metering interconnections is yet to be added.
22 Net energy metering is a billing mechanism that credits solar energy system owners for the
electricity they add to the grid.
23 More statistics compiled from the California Solar Statistics database, as well as the original data
set, are available at https://www.californiasolarstatistics.ca.gov/.
23

In contrast, the measurement and evaluation reports funded by the California Public
Utilities Commission (CPUC) on energy efficiency programs, though voluminous, are
focused specifically on verifying the savings claimed by the investor-owned utilities. The
underlying data are not provided to the public or to the building industry in ways that
support financial decision-making or business opportunity assessments. The publicly
owned utility (POU) energy efficiency reports to the Energy Commission similarly do not
contain this sort of information. Data similar to that from the California Solar Initiative
database should be made publicly available for all efficiency projects in the state that take
advantage of ratepayer-funded financial assistance.
Building owners also need easy, routine access to their building energy use data so that
ongoing benchmarking, monitoring, and efficiency opportunity identification can be
integrated into their core business practices. Building owners of multi-tenant buildings
almost always struggle with burdensome processes to acquire whole building energy use
data from utilities.
State and local governments need access to building energy use data along with relevant
building characteristics, to establish baselines and track progress toward efficiency goals.
Local governments often lack the resources and the data access to identify the energy
savings potential of the commercial buildings and homes in their jurisdictions. Local
governments need this information to appropriately target efficiency efforts as part of their
climate action plans.
The smart meter infrastructure in much of California provides a transformative opportunity
to measure and monitor electricity usage at a much finer level of detail than what was
historically possible. This infrastructure should allow consumers to access their usage data
easily and routinely, along with simple, reliable tools to extract actionable recommendations
from the data. These data allow consumers to compare their usage with peer groups,
monitor and track their usage over time, and/or share their data (if they so choose) with any
number of analytics firms to gain a better understanding of their energy usage and savings
opportunities. The availability of this granular usage data should also encourage California
policy makers to think differently about energy efficiency savings verification approaches
that can be implemented more quickly and can more directly assess the impact of a project
on energy consumption. The Energy Commission is working with the CPUC to identify
existing data that can be made publicly available to meet some of these market needs. The
Energy Commission will also update its Title 20 data collection regulations in 2016 to obtain
data needed for both long-term demand forecasting and to implement specific Plan
strategies.
For energy efficiency and other resources to reliably displace traditional energy supply
resources, the market needs the data collection and analysis infrastructure to measure
efficiency savings at the meter. Depending on the specific need, measurement could be done
over time on a specific project or, likely more commonly, for a group of projects in
aggregate. Pacific Gas and Electric (PG&E) and the U.S. Department of Energy (DOE)
24

sponsored work in this area for commercial whole-building efficiency project savings
verification. 24 The Open EE Meter platform 25 may be used soon in California utility
programs to verify and track whole-house upgrade project savings. The Energy
Commission and the CPUC should build on these nascent efforts to encourage development
of measurement and verification protocols that can be used by the market to quantify
efficiency savings quickly and effectively. This could improve customer confidence, enable
differentiation among contractors, and ultimately will enable groups of efficiency projects to
be bid into energy supply procurement auctions.
Commercial and Multi-Family Energy Use Benchmarking
Benchmarking building energy use is the comparison of annual energy usage to that of
other like buildings, to understand the relative energy performance of a building. In 2007
California passed Assembly Bill 1103 (Saldana, Chapter 533, Statutes of 2007), the first
statewide commercial building benchmarking and disclosure law, and in 2013 the Energy
Commission implemented regulations to administer this law. These regulations have been
largely ineffective, in part due to difficulties for building owners to obtain whole-building
energy use data from utilities. With the exception of the Sacramento Municipal Utility
District, California utilities have required burdensome processes for provision of such data,
making compliance with the state’s benchmarking and disclosure requirements difficult.
California’s most progressive local governments have already implemented or are planning
to institute local benchmarking ordinances. However, the success of these programs is now,
and will continue to be, thwarted by the inaccessibility of whole-building data. Other local
governments are waiting for the data access issue to be resolved before they propose
benchmarking ordinances in their jurisdictions.
The Energy Commission is revising the AB 1103 regulations, including a requirement for
utilities to map utility meters to buildings. This meter data mapping requirement will
promote whole-building data access; however, it alone is not sufficient for the success of
local and statewide benchmarking programs. The updated AB 1103 regulations also seek to
establish meter data aggregation protocols that utilities will use to provide whole-building
data to building owners for building energy use benchmarking. Although the AB 1103
regulations apply only to benchmarking completed for transaction-based disclosures, the
Energy Commission intends that the whole-building data access protocols established
under AB 1103 be used as a statewide precedent for utilities providing whole building data
access to building owners for any type of energy use benchmarking activity. Benchmarking
is first a management practice for building owners to track energy use over time and
24 Jump, Price, Granderson, and Sohn. Functional Testing Protocols for Commercial Building Efficiency
Baseline Modeling Software. Lawrence Berkeley National Laboratory. LBNL-6593E, 2014
25. http://www.openeemeter.org.
25

understand opportunities for efficiency improvements. With or without local or state
mandates, building owners should have routine and easy access to whole-building energy
data.
The plan discusses other limitations with AB 1103, most notably that the trigger points for
disclosure of the building energy use benchmarks in this law are limited to the time of a
whole-building sale, lease, or finance. Three percent or less of California’s commercial
buildings is thus subject to this law each year. The plan recommends a broader statewide
benchmarking and disclosure program for the state’s large nonresidential and multifamily
buildings, in which building owners will benchmark their buildings periodically, with
eventual public disclosure of the benchmarking metrics. This type of benchmarking and
public disclosure program is consistent with what many U.S. cities have implemented over
the last several years. The difference between the two approaches is shown in Figure 7,
where blue bars represent the nonresidential floor space benchmarked under AB 1103
(covering units greater than 10,000 square feet at time of transaction), while red bars
represent a benchmarking system where units greater than 50,000 square feet are
benchmarked at regular intervals.
Figure 7: Comparison of Floor Space Covered by Benchmarking Strategies
Source: Energy Commission, Existing Buildings Energy Efficiency Action Plan.
Assembly Bill 802 (Williams, 2015), among other things, eliminates the statutory language of
AB 1103, and replaces it with new provisions related to a broad statewide benchmarking
and disclosure program. Among these provisions, AB 802 requires utilities to maintain
energy usage records for both commercial and large multifamily buildings, and to provide
aggregated energy usage data to the building owner, owner’s agent, or operator upon
26

equest. The legislation also allows the Energy Commission to adopt regulations providing
for the collection and public disclosure of energy benchmarking.
Applying Building Energy Efficiency Standards to Existing Buildings
The Building Energy Efficiency Standards predate the strategies in the AB 758 action plan and
play an essential role in California’s efforts to ensure high efficiency of both new and
existing buildings. The standards have been a part of California’s regulatory landscape since
the late 1970s and have had a profound cumulative effect on statewide energy consumption.
The standards make mandatory the inclusion of feasible, cost-effective advancements in
building energy efficiency and apply both when new buildings are built and when
additions and alterations are made to existing buildings.
Over time, those requirements have steadily improved California’s building stock, at the
same time enhancing not only energy efficiency, but indoor air quality, thermal stability,
and occupant comfort. Measures that apply to existing buildings are generally based on
measures established for newly constructed buildings, either by determining that the same
measures are feasible and cost-effective to implement in an addition or alteration, or by
modifying a measure established for a newly constructed building. The standards are
updated every three years, as a part of the general updates to all parts of the California
Building Code.
As the Energy Commission implements the 2016 Standards update, it will take the following
steps can be taken to enhance the effect of these updates on existing buildings:
• Provide early publication of compliance manuals, documents, and software. This
gives builders and the building industry additional time to familiarize themselves
with the 2016 requirements, and Home Energy Rating System (HERS) Providers
opportunity to develop their applications for approval and to train technicians in
advance of the January 1, 2017, effective date. Early availability is particularly
important for addition and alteration projects, which often have much shorter
timelines than new building projects.
• Work with the CPUC and local utilities to develop and offer early compliance
incentive and training programs for addition and alteration projects.
• Work with local jurisdictions pursuing efficiency ordinances for existing buildings.
The Energy Commission is aware of several jurisdictions pursuing retrofit programs,
and can work with local officials to ensure compliance with the Standards.
As the Energy Commission looks forward to the 2019 Standards development cycle, it will
take the following steps to synergize Standards updates with Plan strategies:
• Work with stakeholders, including other state agencies and local governments, to
explicitly quantify the incremental costs of permitting and compliance for typical
retrofit projects, and their effect on overall measure cost-effectiveness.
27

• Clarify and streamline the regulatory Standards language, paying particular
attention where stakeholders identify added costs and other roadblocks to
implementing the requirements for existing buildings. This includes tailoring the
additions and alterations requirements to what can be practically and cost-effectively
accomplished in an existing building. Working within an existing building presents
numerous constraints and various types of transactions costs that are not found in
newly constructed projects.
• Simplify and automate, wherever possible, the compliance pathways, options, and
associated forms and materials necessary for demonstrating compliance with energy
efficiency standards.
• Consider amendments to the Standards that establish tailored requirements for
multifamily buildings. The designs of these buildings often incorporate aspects of
both nonresidential buildings and single-family homes.
• Continue its collaboration with the CPUC to develop appropriate mechanisms for
offering incentives for elective projects in existing buildings (for example, additions
and alterations) that result in the buildings being brought up to current code.
AB 802, in addition to aforementioned provisions on benchmarking energy data, will also
revisit the treatment of utility incentives for existing buildings. Currently, electrical and gas
corporations may offer incentives for energy efficiency measures only if those measures
improve a building beyond existing efficiency codes and standards. AB 802 instead requires
the CPUC to authorize incentives for energy efficiency measures that improve a building’s
efficiency beyond actual current conditions. This change from “code-as-baseline” to “actualas-baseline”
will allow for a broader array of incentive programs with lower costs and
higher potential efficiency savings.
Asset Ratings
Evaluating building energy performance and identifying opportunities for improvement are
critical components of the plan. The Energy Commission is committed to clarifying the
difference between, on the one hand, scoring the relative efficiency of building properties as
assets and, on the other, assessing the energy performance of a given building to identify the
best opportunities for its occupants to reduce energy use.
The Energy Commission intends to separate asset ratings from performance assessments.
Asset ratings can be helpful specifically for real estate transactions for owners and buyers to
value building property. Such asset ratings should be disclosed along with other property
details to help inform the purchase decisions of prospective buyers.
28

Public Resources Code Section 25942 26 directs the Energy Commission to establish criteria
for a statewide home energy rating program for homes: to create a consistent, accurate, and
uniform asset rating system based on a statewide rating scale that can differentiate the
energy efficiency levels among California homes.
The Whole-House HERS rates the efficiency of homes on a scale from 0 to 250 relative to a
reference home built to meet the 2008 BEES. California Whole-House HERS provides
California homeowners and prospective home buyers with information about the energyrelated
characteristics of the homes they inhabit or are considering for purchase. However,
there has been limited market uptake of Whole-House HERS to date. This voluntary assetrating
approach is perceived to be expensive, and the ability of HERS Raters to produce
credible ratings is in question.
Assessment Tools
An asset rating helps owners and occupants to understand the building’s physical
infrastructure; however, this alone is insufficient to identify and prioritize measures that
most effectively improve a building’s performance. For decisions on how to reduce energy
use in a specific building, an assessment must be made that considers its actual occupants
and their energy use patterns. Such performance assessments generally provide
recommendations that are specific to the building, related equipment and appliances, and
how the occupants interact with the building in practice. The Energy Commission intends
that performance assessment tools be deployed by the private market, not by the
government. Instead, government’s role should be to establish a set of minimum criteria for
building performance assessment tools so that the industry delivers reasonably reliable
assessments and consumers know what to ask for and expect when hiring professionals to
assess building efficiency opportunities.
The Energy Commission is working to resolve these issues and to clarify the role of energy
assessments, if any, in the Whole House HERS program. In late 2012, the Energy
Commission opened the HERS Order Instituting Informational (OII) Proceeding, Order No.
12-1114-6, to identify potential procedures and other actions to improve the HERS program
and better define its role in the marketplace for existing building upgrades. Information
gathered through the OII process will lead to a rulemaking specific to Whole-House HERS.
In the fall 2015, the Energy Commission will hold a public workshop to prioritize the
various issues and will begin to develop draft regulations based on the OII record. The
Energy Commission is targeting the spring of 2016 to initiate the Whole-House HERS Order
Instituting Rulemaking. To inform the update to the Whole-House regulations, the Energy
Commission is working to align California’s energy asset rating approach with national
26 Warren-Alquist Act (Public Resources Code section 25000 et seq.),
http://www.energy.ca.gov/reports/Warren-Alquist_Act/.
29

systems, and to understand the potential role, if any, for building performance assessments,
in the HERS Whole House program.
Plug-Load Efficiency
Plug loads result from devices that are plugged into power outlets, including electronic
products such as computers, TVs, and cell phones; household appliances such as
refrigerators and clothes washers; and miscellaneous equipment such as vacuums, power
tools, and battery chargers. Reducing plug-load energy consumption is a key part of
reducing the energy footprint of existing buildings. Plug-load efficiency will also be critical
for meeting the state’s goals for zero-net energy (ZNE) new buildings. Plug-load devices,
unlike some built-in energy end uses, are typically selected by the occupant. They are often
more dependent on the occupant’s behavior and habits. Going forward, new challenges for
building designers are making plug loads and equipment selection part of the basic building
design, and educating tenants and owners on the importance of efficient selection and
operations of their plug-in appliance purchases.
Energy use by plug loads is growing rapidly in both the residential and commercial sectors.
For example, the average house that contained only four or five plug-load devices 20 years
ago now has as many as 65. 27 Combined, plug-load devices account for about two-thirds of
California home electricity use. 28 This fraction is projected to grow to 70 percent by 2024. 29
At this pace, plug-load energy use will hinder achievement of the state’s efficiency goals.
Appliance Efficiency Standards
The California Public Resources Code Section 25402 mandates the Energy Commission to
“reduce the wasteful, uneconomic, inefficient, or unnecessary consumption of energy.” The
Public Resources Code authorizes the Energy Commission to set minimum levels of
operating efficiency that will reduce the growth in energy consumption. The Commission
carries out this mandate by setting energy efficiency standards for appliances that are not
regulated by the U.S. DOE. These standards are found in Title 20 of the California Code of
Regulations. The Energy Commission, however, is often preempted by the U.S. DOE’s
authority. For example, the U.S. DOE set standards for refrigerators, dish-washers, and
27 Natural Resources Defense Council, Plug Load Efficiency Strategies, presentation at IEPR
commissioner workshop on Plug Load Efficiency, June 18, 2015.
28 Pacific Gas and Electric, Comments of Pacific Gas and Electric Company on Plug Load Efficiency written
comments from IEPR commissioner workshop on Plug Load Efficiency,
http://docketpublic.energy.ca.gov/PublicDocuments/15-IEPR-
05/TN205273_20150707T143450_Valerie_Winn_Comments_Pacific_Gas_and_Electric_Company_Plug
_Loa.pdf.
29 Natural Resources Defense Council, “Plug Load Efficiency Strategies,” presentation at IEPR
commissioner workshop on Plug Load Efficiency, June 18, 2015.
30

clothes dryers, among other appliances, which preempts the Energy Commission from
adopting standards for these appliances.
When the Energy Commission has adopted standards for appliances that were not
preempted, it has often set the stage for regional and national standards. In developing
standards, the Energy Commission often works closely with other member jurisdictions in
the Pacific Coast Collaborative, an association composed of the states of California, Oregon,
and Washington, and the Canadian province of British Columbia.
For instance, California’s television standards were adopted by Oregon, Connecticut, and
the Canadian province of British Columbia. California’s battery chargers standards were
subsequently adopted by Oregon and British Columbia, and the U.S. DOE is proposing to
increase the stringency of its proposed battery charger standards to achieve the savings of
California’s standards at a national level. 30 Standards for external power supplies were
adopted by all states and the international community.
In the commercial sector, plug-loads consume 23 percent of the electricity in California
office buildings. 31 Computers, monitors, printers, peripherals, audio-visual equipment, and
telephony comprise 86 percent of this plug-load energy use, with computers and monitors
alone accounting for about two-thirds of this amount. 32 In the residential and commercial
sectors, 8.3 million computers of various types are sold in California each year. 33
For these reasons, the Energy Commission is considering energy efficiency standards for
computers, monitors, and displays through its Title 20 authority. 34 Such standards would
reduce the average energy use for a typical computer, central processing unit, and display,
without affecting functionality or performance, using available, off-the-shelf technologies.
The proposed standards will save more than 2,700 GWh per year statewide after stock
30 Standards adopted in 2012 for battery chargers will save enough electricity to power nearly
350,000 households, all the homes in a city roughly the size of Bakersfield. Once fully implemented,
California ratepayers will save about $306 million per year from battery charger standards alone.
31 ECOVA, Commercial Office Plug Load Savings and Assessment: Executive Summary, December 2011.
32 California Public Utilities Commission. Energy Efficiency Strategic Plan, Research and Technology
Action Plan 2012-2015, page 4-1.
33 Singh, Harinder, Ken Rider. 2015. Staff Analysis of Computer, Computer Monitors, and Signage
Displays. California Energy Commision. CEC-400-2015-009-SD,
http://docketpublic.energy.ca.gov/PublicDocuments/14-AAER-
02/TN203854_20150312T094326_Staff_Report__FINAL.pdf.
34 California Energy Commission. 2015 Appliance Efficiency Pre-Rulemaking – Computers, Computer
Monitors, and Signage Displays. http://www.energy.ca.gov/appliances/2014-AAER-2/prerulemaking/.
31

turnover. The standards, which would take effect in January 2018, will also save businesses
and consumers an estimated $434 million on their electricity bills. 35
Plug-Load Research
Research can help ease development of appropriate and beneficial standards. For instance,
the Energy Commission’s plug‐load research is projected to result in estimated savings of $9
billion between 2005 and 2025 through adoption of three appliance efficiency standards for
televisions, external power supplies, and battery chargers. 36
Many plug-load devices consume power even when not in use, known as standby or idle
loads, costing consumers money while providing little or no utility. Most of these devices
lack proportionality between the energy consumed and the useful work delivered by the
device. 37 About 23 percent of residential plug load is caused by “always-on,” but not always
in-use, equipment, such as microwaves, burglar and security systems, sprinklers, alarms,
thermostats, and displays. Similarly, much of the information technology equipment in
commercial buildings is left on around the clock, and power management is not being fully
used. 38 In September 2014, the Institute of Electrical and Electronics Engineers announced
that software management company AGGIOS, Inc. and more than 30 leading electronics
companies began work on a new standard for energy-proportional mobile and “wallpowered”
electronic systems. The standard will enable specifying, modeling, verifying,
designing, managing, testing, and measuring the energy features of a device. 39
The Energy Commission has an established track record in research and development on
this issue. Past research by the Energy Commission’s Public Interest Energy Research (PIER)
35 Singh, Harinder, Ken Rider. 2015. Staff Analysis of Computer, Computer Monitors, and Signage
Displays. California Energy Commision. CEC-400-2015-009-SD,
http://docketpublic.energy.ca.gov/PublicDocuments/14-AAER-
02/TN203854_20150312T094326_Staff_Report__FINAL.pdf.
36 Battery chargers- http://www.energy.ca.gov/appliances/battery_chargers/documents/2010-10-
11_workshop/2010-10-11_Battery_Charger_Title_20_CASE_Report_v2-2-2.pdf.
Televisions- http://www.energy.ca.gov/appliances/2008rulemaking/documents/2008-04-
01_workshop/2008-04-04_Pacific_Gas_+_Electric_Televisions_CASE_study.pdf.
External power supplyhttp://www.energy.ca.gov/appliances/2004rulemaking/documents/case_studies/CASE_Power_Suppli
es.pdf.
37 AGGIOS, “2015 IEPR Staff Workshop on Plug Load Efficiency,” presentation at IEPR
commissioner workshop on Plug Load Efficiency, June 18, 2015.
38 Ibid.
39 Business Wire. AGGIOS Heads IEEE Standardization of Unified Hardware Abstraction (UHA) for Energy Proportional
Electronic Systems. September 22, 2014.
32

program and the IOUs focused on set‐top boxes, component power display, external power
supplies, office electronics, battery chargers, flat‐screen televisions, home stereo/audio
systems, 24/7 kiosks (for example, ATMs), multi‐media computers, and high-performance
and ultra-efficient hybrid computers.
Many common electronic devices such as televisions, computers, and game consoles also
lack the ability to measure and report energy use or receive control signals, but are designed
to connect to the Internet. This makes many devices ideal candidates for networking. The
integration of plug-load controls can reduce active and idle loads and result in better load
management and response to grid conditions. Through intelligent energy (combined with
information such as weather forecasts, occupancy forecasts, and energy prices), energy
efficiency can be incorporated into daily practices and save consumers money. Key to this is
the development of standardized communication and application protocols that can identify
which devices are using energy, and how much they are using at any given time.
Utility Energy Efficiency Procurement
California utilities have been offering energy efficiency programs to their customers since
the 1970s. The CPUC oversees the energy efficiency programs of the IOUs, while the
POUs regulate their own energy efficiency programs. Through these programs, both the
IOUs and POUs play significant roles in meeting California’s energy and climate policy
objectives as these programs help reduce emissions and are the lowest-cost energy
resource option.
The Legislature has passed several bills to promote increased energy efficiency via
utilities’ involvement in California. SB 1037 (Kehoe, Chapter 366, Statutes of 2005) requires
the IOUs to meet unmet resource needs through all available energy efficiency that is costeffective,
reliable, and feasible. SB 1037 also requires the CPUC, in collaboration with the
Energy Commission, to identify all potentially achievable cost-effective electric and
natural gas energy efficiency measures for the IOUs, set targets for achieving this
potential, review the energy procurement plans of the IOUs, and consider cost‐effective
supply alternatives such as energy efficiency. More recently, SB 350 requires the CPUC to
review and update policies governing investor-owned utilities’ efficiency programs as
part of the state’s 2030 goals for energy efficiency savings.
In addition to these IOU requirements, SB 1037 requires that all POUs, regardless of size,
report investments in energy efficiency programs annually to their customers and to the
Energy Commission. AB 2021 (Levine, Chapter 734, Statutes of 2006) requires the Energy
Commission, along with the CPUC, to develop a statewide estimate of energy efficiency
potential along with statewide annual targets over a 10-year period for California’s IOUs
and POUs.
33

Investor-Owned Utilities Progress and Update
The CPUC released a report in March 2015 with the evaluation, measurement, and
verification (EM&V) results for the 2010-2012 IOU portfolio cycle. 40 Collectively, the 2010-
2012 evaluated savings from energy efficiency programs administered by the IOUs
exceeded the goals for energy and gas savings but fell short in peak savings numbers.
About 90 percent of the savings achieved during this program cycle occurred in the
commercial and residential sectors. The majority of the electricity savings came from
lighting measures and heating, ventilation, and air conditioning (HVAC) upgrades. Table
1 summarizes the goals, reported savings, and evaluated savings for each IOU during the
2010-2012 program cycle.
Table 1: CPUC Goals and IOU Evaluated Savings for 2010–2012
2010-2012 PG&E SCE SDG&E SCG Total
CPUC Goals
Electricity Savings (GWh) 3,110 3,316 540 - 6,966
Peak Savings (MW) 703 727 107 - 1,537
Natural Gas (MMth) 49 - 11 90 150
IOU Reported Savings
Electricity Savings (GWh) 3,924 4,458 786 - 9,168
Peak Savings (MW) 703 825 129 - 1,657
Natural Gas (MMth) 68 - 4 83 155
CPUC Evaluated Savings
Electricity Savings (GWh) 3,256 3,859 630 - 7,745
Peak Savings (MW) 553 652 103 - 1,308
Natural Gas (MMth) 53 - 9 111 173
Performance against 2010-2012 Goals
Percent of GWh Goals 105% 116% 117% - 111%
Percent of MW Goals 79% 90% 96% - 85%
Percent of MMth Goals 108% - 79% 123% 115%
Source: CPUC 2010-2012 Energy Efficiency Annual Progress Evaluation Report, March 2015.
For 2013 and 2014, efficiency savings have been estimated by IOUs but not yet verified by
third-party evaluators. However, according to the IOU estimates, the IOUs collectively
surpassed their electricity, peak, and gas savings goals set by the CPUC. For 2013, Pacific
Gas and Electric (PG&E), Southern California Edison (SCE), and Southern California Gas
Company (SoCal Gas) reported meeting all of their goals, while San Diego Gas & Electric
Company (SDG&E) fell slightly short in achieving its peak and gas goals. For 2014, all the
40 CPUC, 2010-2012 Energy Efficiency Annual Progress Evaluation Report, March 2015. Available at
http://www.cpuc.ca.gov/NR/rdonlyres/052ED0ED-D314-4050-9FAA-
198E45480C85/0/EEReport_Main_Book_v008.pdf.
34

IOUs reported meeting their goals. Lighting measures and HVAC again made up the
majority of electricity savings while natural gas savings came from process improvements
in the industrial sector. For this two-year cycle, the CPUC approved over $1.7 billion
dollars for the IOUs to spend on energy efficiency programs and over $78 million to be
spent on EM&V studies.
Table 2 below summarizes these 2013 and 2014 results. The estimated 2013 and 2014 energy
savings of 2,446 GWh and 2,537 GWh represented about 1.2 percent of overall electricity
consumption for each year. (These savings are self-reported estimates, not yet
independently verified by third-party evaluators.)
Table 2: CPUC Goals and IOU Reported Savings for 2013 and 2014
2013 PG&E SCE SDG&E SCG Total
CPUC Goals
Electricity Savings (GWh) 853 922 221 - 1,996
Peak Savings (MW) 145 181 43 - 369
Natural Gas (MMth) 21 - 2 24 47
IOU Reported Savings
Electricity Savings (GWh) 1,080 1,145 221 - 2,446
Peak Savings (MW) 191 193 33 - 417
Natural Gas (MMth) 31 - 1 25 57
2014 PG&E SCE SDG&E SCG Total
CPUC Goals
Electricity Savings (GWh) 832 924 212 - 1,968
Peak Savings (MW) 132 177 41 - 350
Natural Gas (MMth) 21 - 2 23 46
IOU Reported Savings
Electricity Savings (GWh) 1,084 1,216 237 - 2,537
Peak Savings (MW) 196 211 42 - 449
Natural Gas (MMth) 30 - 2 27 59
Sources: 2013-2014 goals are from CPUC Decision 12-11-015, November 8, 2012. Reported savings numbers are from the
IOUs' Annual Reports and are unevaluated savings numbers.
In past years, the CPUC approved three-year energy efficiency program cycles, most
recently 2010-2012. Often, these three-year program cycles are followed by a one- or twoyear
bridge period, such as 2013-2014. In November 2013, the CPUC released an Order
Instituting Rulemaking establishing a proceeding that would address post-2014 energy
efficiency issues. 41 Some of the key objectives of this proceeding include greater funding
41 CPUC. Order Instituting Rulemaking Concerning Energy Efficiency Rolling Portfolios, Policies, Programs,
Evaluation, and Related Issues. November 21, 2013.
http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M081/K631/81631689.PDF.
35

stability for energy efficiency program administrators and implementers; reduced
transaction costs for program implementation; better coordination with demand forecast,
procurement planning, and transmission planning; and transparent and timely forecasts of
program savings and use of those forecasts to enhance energy efficiency portfolios.
The first phase of the proceeding concluded in October 2014 with Decision D.14-10-046,
which authorized ten year funding of the energy efficiency portfolio (through 2024) at
current levels. The current (second) phase of the proceeding is developing the review and
approval processes for this ten year funding authorization, which the CPUC is referring to
as a “rolling portfolio cycle,” and which should avoid the stop/start nature of the previous
triennial portfolio cycles and promote long-term energy efficiency projects. In addition, a
longer portfolio period will project a firm future commitment to consistent funding for
energy efficiency programs.
A proposed decision describing the new rules of engagement associated with the rolling
portfolio cycle was made public in August 2015, although the CPUC has not yet voted on it.
One of the key changes that the proposed decision identifies is the use of firm deadlines for
each step in the regulatory process. This approach will allow for different types of EM&V
studies, including studies with faster turn-around times, and will also allow EM&V results
to be incorporated into the portfolio on a more timely and more frequent basis
Publicly Owned Utilities
California's POUs energy efficiency programs are also an essential component in managing
growing electricity demand and reducing GHG emissions. There are more than 40 POUs in
the state that provide nearly one-quarter of California’s total electricity supply; the 15
largest POUs represent roughly 95 percent of the POU electricity sales. Similar to IOUs,
POUs administer programs designed to increase energy efficiency within their territories.
POUs are organized in various forms, including municipal districts, city departments,
irrigation districts, or rural cooperatives.
Following legislative mandates, for almost a decade, the California Municipal Utilities
Association (CMUA) has annually filed the Energy Efficiency in California’s Public Power
Sector status report on behalf of the POUs. Energy Commission staff assesses the progress
made specifically by POUs and discusses efforts to help POUs increase the amount of
energy efficiency in their service territories.
POU Annual Program Expenditures and Savings
In 2014, POUs spent a combined $170 million on energy efficiency programs, a 26 percent
increase over 2013. The POUs’ electricity savings totaled 625 GWh in 2014, an increase of 20
percent over 2013. POUs also reported a combined 110 MW in peak demand savings, a 24
percent increase over 2013.
36

Table 3: 2013 and 2014 POUs Efficiency Savings and Expenditures
2013 2014
LADWP
Electricity Savings (Gigawatt hours) 171 252
Demand Reduction (Megawatt ) 23 35
Efficiency Expenditures ($ Millions) $50 $78
SMUD
Electricity Savings Gigawatt hours 174 142
Megawatt 27 25
Efficiency Expenditures ($ Millions) $35 $41
34 Other POUs*
Electricity Savings (Gigawatt hours) 176 231
Demand Reduction (Megawatt) 39 50
Expenditures ($ Millions) $49 $51
POU Total
Electricity Savings (Gigawatt hours) 521 625
Demand Reduction (Megawatt) 89 110
Efficiency Expenditures ($ Millions) $134 $170
Source: California Municipal Utility Association, Energy Efficiency in California’s Public Power Sector: A Status Report, March
2014 and March 2015. *While there are more than 40 POUs within California, electricity savings of 36 reporting POUs are
assessed by the Energy Commission staff.
After a few years of leveling off, the POUs’ annual energy efficiency program expenditures
are now at the highest point since 2006. 42 The two largest POUs, Sacramento Municipal
Utility District (SMUD) and Los Angeles Department of Water and Power (LADWP), jointly
represent nearly half (55 percent) of total POU retail electricity sales. As shown in Table 3,
these two largest POUs reported combined expenditures of nearly $120 million and roughly
394 GWh in electricity savings. Of the remaining 34 POUs that report expenditures and
savings to the Energy Commission, 13 reported increased expenditures, and 21 reported
decreased expenditures. The reasons for year-to-year changes in expenditures and reported
electricity savings differ for each utility and depend on its unique characteristics, such as
customer base, geographic location, and size.
LADWP, the largest POU in the nation, continued implementation of more than 20 energy
efficiency programs, including the launch and ramp-up of three major direct install
programs for low-, moderate-, and fixed-income customers, both residential and nonresidential.
These include the Home Energy Improvement Program, Small Business Direct
Install, and the Los Angeles Unified School District Direct Install Program.
42 Previous peak of $146 million in POUs’ program expenditures was in 2009. Energy Efficiency in
California's Public Power Sector Status Report, March 2015 at http://cmua.org/wpcmua/wpcontent/uploads/2015/03/2015-FINAL-SB-1037-Report.pdf.
37

Although SMUD, the second largest POU in California, added almost 4,000 new customers
in 2014, electricity sales for the year remained relatively flat. 43 SMUD also reported $6
million increase in efficiency expenditures compared to 2013, while electricity savings in
2014 decreased by 18 percent.
The POUs’ savings reported here have not been modified or verified by independent EM&V
studies. Unlike the IOUs, for which the CPUC can report evaluated savings, the POUs do
not yet have uniform post-program EM&V methods, making it impossible to gather and
analyze the actual results. Therefore, Energy Commission staff continues working toward
standardizing pre-program savings estimates reported by POUs as directed in previous
IEPRs. The CMUA recently sponsored a Technical Reference Manual that “provides the
methods, formulas, and default assumptions used for estimating energy savings and peak
demand impacts from energy efficiency measures and projects.” 44 Greater collaboration
among the Energy Commission, utilities and a growing list of stakeholders will be involved
in assessing whether existing EM&V approaches to post-program reporting are adequate, or
if a new direction is needed that will include the measurement of POUs GHG reductions.
POU Progress Toward 10-Year Goals
Following legislative mandates, the Energy Commission adopted POU energy efficiency
targets in 2007 of 6,630 cumulative GWh by 2016 – roughly two-thirds of POUs’
economically feasible savings estimated through that year. 45 Assuming a linear trajectory
toward this 2016 goal, the cumulative eight-year (2007-2014) electricity savings target for 36
POUs is 5,049 GWh. The POUs’ reported combined electricity savings of 3,809 GWh
represents roughly 75 percent of the 2014 benchmark. SMUD and LADWP combined
achieved roughly 72 percent of their cumulative 2014 benchmark, while the other 34 POUs
achieved roughly 82 percent.
In 2013, the CMUA submitted a 10-year (2014-2023) energy efficiency potential study
coordinated on behalf of multiple POUs. 46 Using the Energy Efficiency Resource Assessment
Model, the study developed updates for 36 POUs, excluding LADWP. Nexant Inc.
subsequently conducted a separate energy efficiency potential study for LADWP in 2014,
43 SMUD 2014 Annual Report, https://www.smud.org/en/about-smud/companyinformation/documents/2014-annual-report.pdf.
44 Energy & Resource Solutions, “Savings Estimation Technical Reference Manual for the California
Municipal Utilities Association,” May 5, 2014. Available at: http://cmua.org/wpcmua/wpcontent/uploads/2014/05/CMUA-_TRM-manual_5-5-2014_Final.pdf.
45 Achieving All Cost-Effective Energy Efficiency for California. December 2007.
http://www.energy.ca.gov/2007publications/CEC-200-2007-019/CEC-200-2007-019-SF.PDF.
46 Energy Efficiency in California's Public Power Sector Status Report. March 2013.
http://cmua.org/wpcmua/wp-content/uploads/2013/03/FINALv3-SB-1037-AB-2021-Report-
Appendices.pdf.
38

which determined that 15 percent electricity savings based on sales forecast by 2020 is
attainable cost-effectively below the avoided cost of generation. 47
Studies of energy efficiency potential typically involve three types of energy savings
potential: technical, economic, and market. “Technical potential” represents the complete
penetration of efficiency measures where they are technically feasible to install. “Economic
potential” represents a percentage of technical potential that is cost-effective as defined by
the results of the Total Resource Cost test. The test calculates the present value of the
benefits produced by the programs to the total program administration costs and customer
costs incurred to invest in the increased levels of efficiency. 48 There is some discussion about
the appropriateness of the TRC test, which may overweight customer costs attributed to
energy efficiency, given that customers adopt measures for a variety of diverse reasons,
within which energy efficiency may be only a small part. Finally, “market potential” is the
percentage of economic potential achievable when program designs, customer preferences,
and market conditions are incorporated. With a few exceptions, the POUs used the market
potential as their officially adopted targets for 2014–2023.
Table 4 summarizes these respective estimates and targets for LADWP, SMUD, and other
POUs. For 2023, the POUs in combination set a target of achieving roughly 46 percent of
their estimated “economic potential” savings. This is comparatively lower than their
aggregated 2007 goal, which represented roughly two-thirds of “economic potential” for
2016. This may be attributable to POUs anticipating that they will exhaust more of their
current means for achieving energy efficiency savings.
47 LADWP Territorial Potential Draft Report Volume 1. Nexant. June 24, 2014.
48 Total Resource Cost benefits include avoided costs of generation, transmission and distribution
investments, as well as avoided fuel costs due to energy conserved by energy efficiency programs.
39

Table 4: 2014-2023 Cumulative Efficiency Savings Potential for Publicly Owned Utilities
LADWP
Technical Economic Market Target
Electricity Savings Potential (Gigawatt hours) 8,813 5,877 6,958 3,596
Demand Reduction Potential (Megawatt) 3,205 1,371 1,773 -
SMUD
Electricity Savings Potential (Gigawatt hours) 4,145 3,017 1,862 1,824
Demand Reduction Potential (Megawatt) 2,016 1,532 771 -
34 Other POUs
Electricity Savings Potential (Gigawatt hours) 7,992 7,105 2,132 1,946
Demand Reduction Potential (Megawatt) 2,328 1,648 540 -
POU Total
Electricity Savings Potential (Gigawatt hours) 20,950 15,999 10,952 7,366
Demand Reduction Potential (Megawatt) 7,549 4,551 3,084 -
Sources: CMUA, Energy Efficiency in California's Public Power Sector Status Report, March 2013
http://www.ncpa.com/~ncpa/wp-content/uploads/2015/02/FINALv3-SB-1037-AB-2021-Report-Appendices.pdf.
LADWP Territorial Potential Draft Report Volume 1, Nexant, June 24, 2014
California Clean Energy Jobs Program
California voters passed the California Clean Energy Jobs Act (Proposition 39) in November
2012. The initiative changed California’s corporate tax code and allocates projected revenue
to the General Fund and the Clean Energy Job Creation Fund for five fiscal years, beginning
in fiscal year 2013/2014. The goal of the Act was to create jobs, and promote and provide
funding for eligible energy projects, such as equipment upgrades, other efficiency
improvements, and clean energy generation. The enabling legislation, Senate Bill 73
(Committee on Budget and Fiscal Review, Chapter 29, Statutes of 2013), focused the effort
on schools, and allocated $56 million to the Energy Conservation Assistance Act (ECAA)
loan program over fiscal years 2013/14 and 2014/15 for low-interest and no-interest
revolving loans and technical assistance. 49 The Proposition 39 program will continue for
eight years, with five years of disbursements from fiscal year 2013/14 through 2017/18 plus
up to three additional years for completion of projects and reporting from recipients to the
Energy Commission.
49 See www.energy.ca.gov/efficiency/proposition39/ for a list of approved Energy Expenditure
Plans, a list of approved ECAA loans, frequently asked questions, assistance, and list server
subscription.
40

The largest responsibility of the Energy Commission under Proposition 39 comes through
administering the Proposition 39 (K-12) program. Under this program, California local
education agencies (LEAs), representing public school districts (K-12), charter schools,
county offices of education, and state special schools, are allocated funds each fiscal year as
determined by the California Department of Education based on student enrollment and
participation in the free and reduced price lunch program. The LEAs may submit Energy
Expenditure Plans (EEPs) for proposed energy projects to the Energy Commission based on
this funding amount.
For fiscal year 2014/15, there were 2,078 eligible LEAs, ranging from a classroom of fewer
than 10 students to an enormous school district of nearly 900,000 students. Given the
tremendous diversity—in geography, climate, facility conditions, and more—the Energy
Commission made it a priority to create a program with sufficient flexibility to meet
individual LEA needs. For example, LEAs have the option to:
• Request fiscal year funding for energy planning.
• Request retroactive funding of energy projects.
• Submit single or multi-year EEPs.
• Submit one EEP for the five-year period.
The Energy Commission reviews the submitted EEPs and, upon approval, notifies the
California Department of Education, which then disburses the allocated funds. The funding
is guaranteed for the five-year period and has a fiscal year rollover through June 30, 2018.
LEAs have two additional years, until June 30, 2020, to complete their approved energy
projects, and another year to submit final reporting.
The Energy Commission focused on measures most prevalent in schools and likely to
achieve expected savings. Eligible projects include the installation of:
• Lighting and lighting controls.
• Heating, ventilation, and air-conditioning systems, such as new rooftop units,
chillers, boilers, and furnaces.
• Pumps, motors, and variable-frequency drives.
• Energy management systems, programmable/smart thermostats, and chiller
controls.
• Equipment for reducing plug load, such as power management and vending
machine misers.
• Building envelope energy-saving measures, such as more efficient windows
and cool roofs.
• On-site clean energy generation, such as solar PV.
41

Since April 2014, more than 641 LEAs (representing 2,319 sites) have requested a combined
$469 million. To date, 526 have been approved totaling $362 million in funding for 1,757
sites. Nearly 80 percent of LEAs (1,646 of 2,078 LEAs) requested energy planning funds in
the first year and are in the planning stage, taking this time to identify and develop energy
projects.
Education and Outreach Efforts
To promote full school participation and to gain further insight regarding program hurdles,
the Energy Commission has developed and is implementing an ambitious outreach plan,
including: a Proposition 39 (K-12) program Web page; statewide training and educational
seminars; ongoing list service announcements; social media program updates; and project
representation published on the California Climate Investment Map. Energy Commission
staff also targets outreach to the largest and smallest LEAs, and to those in disadvantaged
communities, offering relevant technical assistance and support.
Energy Conservation Assistance Act – Educational Subaccount (ECAA-Ed)
Separate from the Proposition 39 (K-12) program, the Legislature provided about $56
million toward the ECAA-Ed subaccount. Of this amount, the Energy Commission allocated
90 percent of the funds, or $50.4 million to zero percent interest rate loans. As of July 2015,
the Energy Commission had received 34 ECAA-Ed loan applications and had approved 24
of them representing a total of $39 million. (An additional 6 applications totaling more than
$10 million are still in review.) These funds will go toward lighting retrofit, HVAC
upgrades, controls, energy generation, and other energy efficiency upgrades. The estimated
cost savings for the approved projects is about $3 million dollars per year, based on
estimated annual reductions of about 17.6 GWh of electricity demand and 36,000 therms of
natural gas demand. This equates to estimated GHG reductions of about 6,282 tons per year.
The remaining $5.6 million from the ECAA-Ed subaccount, or 10 percent of the total
allocation, supports the Bright Schools Program. The Bright Schools Program provides
contractor-supported energy audits for up to $20,000 of technical service per application.
These audits identify eligible energy efficiency projects, informing and easing the EEP
application process. Though the Bright Schools Program has been a successful program for
many years, there was a marked increase in applications for energy audits and technical
assistance due to Proposition 39. Since the start of Proposition 39, the Energy Commission
has received 126 applications under the Bright Schools Program. Final audit reports have
been completed for 63, with applications or draft reports pending for the remainder.
Developing Proposition 39 Data
Access to energy consumption data is critical for understanding baseline conditions of the
state’s schools, as well as for performing Proposition 39 program impact assessments. The
Energy Commission developed working partnerships with IOUs and large POUs for timely
transfer of interval energy use and billing data. The Energy Commission and their partners
created a Common Utility Data Release Authorization form; this format is machine
readable, eliminating transcription and input errors. The data submission will ensure pre-
42

and post-installation energy data is available at the site level. This data transfer and
management infrastructure is a foundational resource that can be used for other initiatives
for which the Commission requires bulk data transfer.
The secure data repository will be updated each year with the latest data with appropriate
levels of information, provided to the Citizens Oversight Board, posted on a public website,
and used in evaluating impacts from Proposition 39.
Citizens Oversight Board
The California Clean Jobs Act and subsequent legislation established the Citizens Oversight
Board, consisting of nine members appointed by the Treasurer, Controller, and Attorney
General (three each), plus ex officio members of the CPUC and Energy Commission (one
each). The Board is required to meet at least four times per year, or as often as the Chair or
Board deems necessary to conduct its business, in accordance with the state’s Bagley-Keene
Open Meeting Act. 50 The first three appointees were selected by the Treasurer in October
2013. At the first Board meeting on September 8, 2015, the Board elected its chair and vice
chair, and received an update from Energy Commission staff on implementation of the
Proposition 39 program to date. The Board is responsible for reviewing expenditures from
the Job Creation Fund, commissioning audits to assess the effectiveness of expenditures,
publishing a complete accounting of all expenditures each year, and providing feedback on
any necessary changes to the Legislature. These requirements are part of an annual report to
the Governor, Legislature, and the public, to be completed within 90 days of the end of the
calendar year.
Accomplishments
The Proposition 39 (K-12) program formally kicked off just six months after Governor
Edmund G. Brown Jr. signed SB 73, with the Energy Commission’s adoption of the Program
Guidelines. 51 Figure 8 illustrates the Proposition 39 (K-12) program timeline from voter
approval of Proposition 39 in November 2012, to LEA final project completion reports due
by June 2021.
50 California Government Code Section 11120 et seq.
51 http://www.energy.ca.gov/2014publications/CEC-400-2014-022/CEC-400-2014-022-CMF.pdf.
43

Figure 8: Proposition 39 Timeline
Source: Energy Commission.
In July 2013, the Energy Commission initiated a comprehensive public process to gain input
for the draft guidelines. This process included focus group meetings, five public meetings,
and three webinars on the draft guidelines to answer questions and receive comments.
These outreach efforts resulted in more than 500 participants and 175 docket submittals. On
December 19, 2013, the Energy Commission adopted the Proposition 39: California Clean
Energy Jobs Act – 2013 Program Implementation Guidelines.
Continuing on this expedited program implementation path, in January 2014, the Energy
Commission launched the Proposition 39 (K-12) program and released the Energy
Expenditure Plan (EEP) Handbook, established an electronic submission process, provided
webinars and training seminars reaching more than 800 LEAs, and established a Proposition
39 (K-12) Hotline contact center.
The first applications started flowing into the Energy Commission in February 2014. By June
2014, the end of the first fiscal year, 2013/14, the Energy Commission had approved 33 EEPs,
totaling $16 million dollars. Some LEAs that submitted these early applications have already
completed projects, achieving energy savings from their Proposition 39 energy investments
within months of the program launch.
The Energy Commission continued to fast-track the program in the second fiscal year,
2014/15, while responding to school needs by launching an online EEP application system
and revising the Guidelines in response to ongoing feedback from schools and their project
44

partners. For this second fiscal year, more than 400 EEPs were approved, totaling $257
million dollars.
As of the beginning of the third fiscal year, 2015/16, the total estimated annual energy cost
savings are more than $25 million. This amount represents projected annual energy cost
savings when all the approved energy projects are completed, and the total estimated jobyears
created when all energy projects are completed are estimated at 1,700 job-years. 52
These energy project implementation jobs include construction, installation contractors,
vendors and purchasers, and school employees. As the project flow ramps up across the
majority of eligible LEAs, these numbers will rise accordingly.
Zero-Net Energy
The Energy Commission’s policy recommendations for newly constructed low-rise homes to
be designed and constructed to be ZNE were discussed in the 2007 IEPR, 2011 IEPR, and
2013 IEPR. These policies are supported by the CPUC in the Long-Term Energy Efficiency
Strategic Plan, by California Air Resources Board (ARB) in the First Update to the Climate
Change Scoping Plan, and in Governor Brown’s Clean Energy Jobs Plan. 53 Governor Brown’s
Executive Order B-18-12 calls for all newly constructed state buildings and major
renovations that begin design after 2025 be constructed as ZNE, as well as 50 percent of the
square footage of existing state-owned building area to be ZNE by 2025. 54
52 A job-year is defined as a full-time job that lasts for one year—not one permanent job. A review of
studies on labor intensity of energy efficiency projects indicates that on average 5.6 direct job-years
are created per $1 million invested for energy efficiency retrofits. A review of two studies on solar
photovoltaic labor intensity indicates that on average 4.2 direct job-years are created per $1 million
invested for solar energy generation system installation. See Zabin and Scott, Proposition 39: Jobs and
Training for California’s Workforce, p. 11,
http://www.irle.berkeley.edu/vial/publications/prop39_jobs_training.pdf. Reported in the Energy
Commission’s Tracking Progress, updated August 31, 2015,
http://www.energy.ca.gov/renewables/tracking_progress/index.html.
53 CPUC, California Energy Efficiency Strategic Plan, January 2011 Update,
http://www.cpuc.ca.gov/NR/rdonlyres/A54B59C2-D571-440D-9477-
3363726F573A/0/CAEnergyEfficiencyStrategicPlan_Jan2011.pdf.
ARB. First Update to the Climate Change Scoping Plan. May 2014.
http://www.arb.ca.gov/cc/scopingplan/2013_update/first_update_climate_change_scoping_plan.pdf.
Governor’s Office of Planning and Research. Clean Energy Jobs Plan.
http://gov.ca.gov/docs/Clean_Energy_Plan.pdf.
54 Governor Edmund G. Brown, Executive Order B-18-2012, April 25, 2012.
http://gov.ca.gov/news.php?id=17508.
45

In the 2013 IEPR, the Energy Commission adopted a definition for ZNE Code Buildings,
developed in collaboration with the CPUC. This ZNE definition calls for a building to
include on-site renewable energy generation that offsets the time-dependent value of the
energy used in the building. However, the published definition implied that the amount of
energy produced (in kilowatt hours) by the onsite renewable energy sources would need to
equal the time dependent valuation (TDV) value of the energy consumed by the building.
This created an inconsistency, essentially describing energy using two different metrics. To
clarify that both the energy generated and consumed should be described in the same
metric, the following revision to the definition is proposed:
A ZNE Code Building is one where the value of the net amount of energy produced
by on-site renewable energy resources is equal to the value of the energy consumed
annually by the building, at the level of a single “project” seeking development
entitlements and building code permits, measured using the California Energy
Commission’s Time Dependent Valuation metric. A ZNE Code Building meets an
Energy Use Intensity value designated in the Building Energy Efficiency Standards
by building type and climate zone that reflect best practices for highly efficient
buildings.
The amount of renewable generation necessary to designate a ZNE Code Building will vary
with multiple factors, including building efficiency, plug-in load use, and climate zone.
These factors are captured in Figure 9, which shows the estimated amount of PV generation
capacity necessary for a building to meet the adopted definition of ZNE. The graph also
shows two additional levels of increased building efficiency and the estimated contribution
from loads not directly regulated by the Standards (not including electric vehicle charging).
46

Figure 9: Estimate of PV Capacity Required for ZNE Code Buildings
Source: Energy Commission staff presentation at May 18, 2015 IEPR workshop.
The 2013 IEPR made the following recommendations as interim steps toward achieving the
2020 residential ZNE goal, with recent progress identified in italics.
• Increase efficiency by 20–30 percent with each building standard update. The
Energy Commission accomplished this through adoption of the 2016 BEES.
• Develop industry-specific training and financial incentives to advance reach
standards and coordinate new utility construction and emerging technology
programs.
The CPUC and IOUs are putting this in place, in coordination with the Energy Commission.
• Track market progress on ZNE construction.
IOUs developed the Residential ZNE Market Characterization Study. 55
• Develop a workforce to build ZNE buildings.
The Energy Commission’s Electricity Program Investment Charge program released a
solicitation for development of an energy efficient building workforce (GFO-15-302).
55 California Measurement Advisory Council. Residential ZNE Market Characterization Study. February
2015. http://www.calmac.org/AllPubs.asp.
47

• Add a voluntary tier for ZNE to 2016 California Green Building Standards.
Developed by the Energy Commission staff; awaiting approval by the Energy Commission
and adoption by the Building Standards Commission.
The 2013 IEPR also highlighted some issues that required further discussion and that must
be addressed to meet ZNE goals by 2020. Those issues included:
• Identifying pathways of compliance for buildings where onsite renewables aren’t
feasible.
• Developing viable accounting and enforcement mechanisms for offsite renewable
projects used to meet ZNE requirements.
• Educating the public about the benefits of and clarifying the correct expectations for
ZNE buildings.
• Identifying the appropriate role of natural gas in the development of ZNE buildings
(required by Assembly Bill 1257 [Bocanegra, Chapter 749, Statutes of 2013]).
• Updating TDV-weighted energy calculations with refined electricity and natural gas
information and costs.
• Refining and updating the plug load assumptions used to determine the amount of
renewables needed for a residential building to reach ZNE
The Energy Commission works with stakeholders to develop solutions for these issues and
will continue doing so going forward. For example, the Commission worked closely with
the CPUC on developing the New Residential ZNE Action Plan 2015-2020 (ZNE Action Plan) 56
and is working with several California utility providers to develop training and incentive
programs for builders seeking to install the high-performing walls and attics that will be
critical cost-effective elements for enabling homes to achieve ZNE. The Energy Commission
will continue to collaborate with stakeholders to address these issues as it develops the 2019
Standards, which will include updating the calculation of TDV and refining estimates of plug
loads in new homes.
To educate the public about the benefits of ZNE Code buildings, the Energy Commission
will also need to work with stakeholders to develop education and outreach materials on
the Standards and ZNE buildings for consumers, contractors, building departments,
builders, and others in the industry that addresses each audience’s specific needs and
questions. This will include setting proper expectations that a ZNE Code Building cannot
guarantee a zero-energy bill. ZNE designs must be based on average behavior determined
56 CPUC and California Energy Commission. New Residential Zero Net Energy Action Plan 2015-2020.
June 2015. http://www.cpuc.ca.gov/NR/rdonlyres/92F3497D-DC5C-4CCA-B4CB-
05C58870E8B1/0/ZNERESACTIONPLAN_FINAL_060815.pdf.
48

long before an occupant moves in; occupant behavior dominates home energy usage and
changes continuously even within the same household. The CPUC is supporting this effort
with the ZNE Action Plan by laying out a framework for building demand and awareness
and identifying leaders to help articulate the benefits of ZNE Code buildings to the public.
For newly constructed low-rise homes that cannot accommodate onsite renewables,
alternative compliance pathways that enable such buildings to meet ZNE Code building
requirements must be developed. The ZNE Code Building definition anticipates considering
“development entitlements” for off-site renewables, such as community-based renewable
resources, as a potential option for builders and developers. Any option that relies on offsite
renewable resources must allow for building department verification to ensure that the
identified resources exist, that they are the correct size for offsetting the energy use of the
buildings they are assigned to, and that their output of these resources is not already
“spoken for” by other approved developments.
For more discussion of reliability issues associated with renewable energy, see Chapter 2.
Issues Regarding Natural Gas Use in ZNE Buildings
ZNE cannot be achieved without carefully addressing the natural gas energy use that is
prominent in today’s buildings. This is particularly true in homes, where roughly 18.5
percent of the natural gas delivered to consumers in California is typically used for space
and water heating, and cooking. 57 One potential way to address this situation would be to
identify strategies to offset residual natural gas usage, such as through uses of waste heat,
including CHP, or potentially through the use of renewable gas resources at the building
site or on a community basis. The latter might rely on a system similar to the previously
discussed “development entitlements” for off-site PV.
Another way to reach ZNE is to replace natural gas appliances, such as gas stoves, water
heaters, and space conditioning units, with electric appliances. This fuel-switching is called
“electrification.” To the extent that California’s generation mix and policy continue to
advance more renewable electricity versus electricity from natural gas, electrification would
realize additional GHG emission reduction benefits. However, at this time, the GHG
emission reduction benefits are not clear because a significant amount of electricity in the
grid comes from natural gas combustion. End-use natural gas appliances also typically have
much higher efficiencies than power plants, while avoiding losses in the electricity system.
Whether end-use electrification applications are cost-effective from a customer perspective
is also not clear. The Energy Commission’s statutes obligate the Energy Commission to meet
specific cost-effectiveness requirements in adopting energy efficiency standards for
buildings and appliances. Therefore, under statute, complete building electrification could
not be pursued within the BEES unless the expected consumer energy costs for electricity
57 U.S. EIA, Natural Gas Consumption by End Use Database, accessed on June 1, 2015.
49

use are lower than those of natural gas use, unlikely in the near-term given the persistently
low cost of natural gas per unit of on-site energy.
When developing a future revision to the BEES, it is important for California to be
consistent in including the costs of future GHG policies that affect separate energy supply
markets, such that all expected consumer energy costs are considered equally. For example,
there are well-established renewable energy policies implemented in California's electricity
procurement market, and the expected consumer costs resulting from these policies are
included in the cost-effectiveness calculations of the standards. However, there are no
commensurate policies specified and implemented in the natural gas supply market. This
discrepancy in policies across energy supply markets results in a method that further lowers
the energy costs for gas technologies compared to electricity technologies over the 30-year
building lifetime considered in the BEES.
In general, further research and analysis are necessary to better understand the trade-offs
associated with electrification. For example, a recent July 2015 City of Palo Alto Utility
Advisory Commission Memo indicated that it may be cost-effective for its residential
customers to switch from natural gas to electric heat pump technologies for water heating,
and that space heating is close to being cost-effective. 58 The same memo indicated that the
overall lifetime cost and operation of electric stoves and clothes dryers was more expensive
versus natural gas. The Energy Commission should complete the analysis needed to
understand what the GHG emission and reduction costs must be for the consumer costs of
electricity to be lower than the consumer costs of natural gas, and at what level of average
electricity carbon intensity would electrification provide environmental benefits. This
analysis includes evaluating the potential similarities and differences between zero-netenergy
building policies and zero-net-carbon building policies, the latter of which are
proposed in the ARB’s First Update to the Climate Change Scoping Plan. 59
Other Sources of Uncertainty
While for the moment the Energy Commission is on course to develop cost-effective
standards for newly constructed ZNE homes by 2020, there remain significant policy
uncertainties at both the state and national levels that threaten to limit the success of ZNE
implementation. Federal tax credits for PV installations are set to expire in 2017. A report by
Lawrence Berkeley National Laboratory found that while the costs of PV installations
continue to decline steadily, reduced incentive payments offset the reductions in installed
58 July 2014 Utility Advisory Board Memo,
https://www.cityofpaloalto.org/civicax/filebank/documents/47998.
59 ARB. First Update to the Climate Change Scoping Plan. May 2014.
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prices that have helped drive rapid market growth. 60 The tax credits have been an important
incentive for advancing renewable energy deployment and meeting the state’s renewable
goals. (For more information about the federal tax credit, see Appendix A. For more
information about renewables, see Chapter 2.) Also, the CPUC is modifying the net energy
metering rules that determine what consumers are paid for electricity contributed back to
the grid. It will be difficult for the Energy Commission to determine cost-effectiveness amid
this policy uncertainty.
Recommendations
Local Government Leadership
• Continue to support innovation by local government. Local governments possess key
authority and unique community connections that make them a critical partner in
gaining ground on energy efficiency, particularly in existing buildings. The Energy
Commission has roughly $11 million in remaining American Recovery and
Reinvestment Act funds planned for reallocation to the most deserving and innovative
local governments. However, the need far exceeds this sum. Scalable, transferable local
government programs should be replicated and expanded.
Data for Informed Decisions
• Collaborate on data provision efforts. The Energy Commission and California Public
Utilities Commission (CPUC) should collaborate on new data provision efforts to
increase both the level and type of building energy efficiency-related project data that
are available to both the building industry and the public.
• Develop standard protocols for meter-based savings verification. The CPUC and the
Energy Commission should establish the measurement and verification protocols
needed to make meter-based savings in incentive programs and efficiency procurement
programs standard practice.
Commercial and Multi-Family Energy Use Benchmarking
• Require utilities to map utility meters to physical locations. Some utilities claim an
inability to match meter numbers and the corresponding energy consumption with an
accurate physical location, such as a building address. Not only is such mapping good
business practice, it also will allow multitenant building owners to comply with current
and future benchmarking regulations by giving them access to necessary data.
60 Barbose, Galen; Naïm Darghouth, Dev; Millstein, Mike; Spears, Michael; Bucklet, Rebecca; Widiss,
Nick; Grue and Ryan Wiser. Lawrence Berkeley National Laborator., August 2015. Tracking the Sun
VIII The Installed Price of Residential and Non-Residential Photovoltaic Systems in the United States.
51

• Implement time-certain benchmarking and disclosure requirements. Time-certain
benchmarking will substantially increase the floor space subject to benchmarking
requirements, above any transaction-based requirements that may remain in place.
Applying Building Energy Efficiency Standards to Existing Buildings
• Evaluate the balance between standards compliance requirements and actual
efficiency improvements for existing buildings. Requirements that provide only
marginal benefits on building efficiency can discourage compliance and miss energy
savings opportunities. Revisions should seek to reduce the compliance burden and
added project cost where there are not commensurate efficiency gains. Such adjustments
need not mean a decrease in realized efficiency, as the Energy Commission has had
success in collaborating with stakeholders to identify equally effective, less burdensome
options for compliance.
• Review standards requirements for additions and alterations. Many of the current
requirements that apply to existing buildings are either based on, or directly identical to,
those applying to newly constructed buildings. However, the cost-benefit profile for
measures in an existing building project may differ from similar measures in new
construction. In reviewing the Standards, the Commission will seek to reflect such
market realities.
• Streamline regulatory language and access to the standards. Stakeholders have begun
identifying specific roadblocks to implementing existing building requirements, which
the Energy Commission will review. Earlier publication of compliance materials can also
simplify compliance, particularly at the transition to each code update.
• Evaluate tailoring specific standards requirements for multifamily buildings. The
designs of multifamily residential buildings often incorporate both residential and
nonresidential sections of the standards. Creating a set of requirements specific to
multifamily buildings would provide a clearer recipe for compliance and ensure that
what’s required of builders makes sense for their buildings. In addition, this effort may
uncover new opportunities for efficiency that are unique to multifamily buildings.
• Develop incentives for existing building efficiency improvements with the CPUC and
utilities. These could include incentives for improving existing buildings at time of
alteration or addition, and encouraging early adoption of updates to the Standards
either by local jurisdictions or within specific building projects.
Asset Ratings
• Increase ease and lower cost of asset ratings. Significantly reduce the costs of
completing the asset ratings mandated by the Home Energy Rating System statute.
Assessment Tools
• Encourage a broader market for building performance assessments. Update Whole-
House HERS Regulations to make the program more viable in that context (including
52

esolving issues identified in the previous Order Instituting Investigation). This includes
establishing recommended protocols for home energy assessments and a clearinghouse
for relevant assessment tools.
Plug-Load Efficiency
• Expand research into plug-load efficiency. Focus research on advancing the
development and deployment of more efficient consumer devices, including electronics
and electronic infrastructure supporting the communication between devices. This
research includes developing and testing efficient low-cost components and low-cost
energy monitoring technologies, and integration of smart and networked controls.
Research should also focus on behavior and system-level efficiency.
• Consider power-scaling standards for plug-load efficiency. Consider standards and
other strategies to reduce the idle loads of devices that are always on. Develop and test
methods to increase on-mode energy efficiency and to enable sleep modes when
electronic equipment, such as game consoles and video conferencing systems, is idle.
• Support improvement in energy monitoring, communication, and remote control
infrastructure for plug-load devices. Among other things, communication protocols
will be needed to allow devices to report data efficiently and flexibly. Enhancement of
building controls can allow energy use to be adjusted in response to occupancy.
• Increase federal collaboration and outreach. Participate in federal rulemakings through
comments on rulemakings, participate in manufacturer interviews as a source of
relevant data, engage in Appliance Standards and Rulemaking Federal Advisory
Committee Working Groups on key appliance types, participate in international and
national codes and standards development groups, and engage in ENERGY STAR®
specification development with the U.S. Environmental Protection Agency. The goal of
these efforts is to ensure that the federal standards and specifications yield the most
cost-effective and technologically feasible benefits to California as available.
Utility Energy Efficiency Procurement
• Continue the transition toward “rolling portfolios” of investor-owned utility
efficiency programs and update the evaluation measurement and verification
(EM&V) process accordingly. The Energy Commission supports the CPUC plan to
improve and accelerate the program development and EM&V processes, as a means to
align program-related analysis and lessons with the Energy Commission’s forecasting
process.
• Continue to work toward standardized savings reporting by publicly owned utilities
(POUs). Assessing whether existing EM&V approaches are adequate, or if a new
direction is needed to quantify energy efficiency gains and greenhouse gas reductions
by POUs.
53

California Clean Energy Jobs Program
• Continue efficient administration of the Proposition 39 Program. Priorities will
include outreach to all local educational agencies to ensure full participation, full grant
usage, and successful project completion. Update guidelines as necessary to incorporate
technical advancements and to address the diversity and needs of local educational
agencies.
• Continue regular meetings of the Citizens Oversight Board. The Board held its first
meeting on September 8, 2015, with a focus on introducing Board members to the
program, reviewing board responsibilities, and selecting a chair and vice chair. Future
meetings will further examine the processes and projects of the program, including
development of the first of the Board’s annual reports.
• Leverage data exchange infrastructure. Oversight of the projects funded under this
program will create an opportunity for collecting data on energy efficiency project costs,
energy consumption trends, anticipated and actual average savings, and other valuable
project information. Where feasible, the Energy Commission and its partners should
take advantage of these data in developing other Commission programs and policies.
Zero-Net Energy
• Continue the progress of building standards that will support zero-net-energy (ZNE).
Previous Integrated Energy Policy Reports have highlighted this goal, and the 2013 and
2016 Standards have furthered progress toward achieving it. Identifying and adopting
further cost-effective efficiency improvements increases the feasibility of offsetting
remaining energy uses with renewable energy.
• Evaluate key differences between ZNE and zero net carbon in new homes. The Energy
Commission’s responsibility for cost-effectively meeting ZNE goals exists in the context
of other initiatives including greenhouse gas emission reduction. Coordinating these
parallel efforts could include, for instance, identifying the cost-effectiveness threshold
for ZNE based on anticipated greenhouse gas emission costs, as well as consumer costs.
• Characterize the role of natural gas, including biogas, in the ZNE context. Part of
identifying the appropriate role of natural gas will involve identifying the point at which
gas is more expensive than electricity for determining cost-effectiveness.
• Incorporate CPUC’s update of net energy metering into future building standards.
The rules and compensation governing net energy metering have a significant effect on
the anticipated lifetime costs and savings associated with photovoltaic systems. This, in
turn, affects the Energy Commission’s ability to establish such systems as part of future
building standards due to a threshold of cost-effectiveness.
• Develop a system to allocate and track the use of off-site renewables. This effort can
lay the groundwork for meeting ZNE requirements with off-site sources under certain
circumstances.
54

• Support extension of federal tax credits for photovoltaic (PV) systems. Current sales
and installations of residential PV systems speak to the success of these credits and the
momentum they have built in the marketplace. The Energy Commission views these
credits as essential for accelerating deployment of renewable energy resources and
achieving aggressive ZNE, Renewables Portfolio Standard, 61 and greenhouse gas
emission reduction goals.
61 The Renewables Portfolio Standard requires the state to meet procure 33 percent of its electricity
from renewable resources by 2020. The Renewables Portfolio Standard is discussed in greater detail
in Chapter 2.
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CHAPTER 2:
Decarbonizing the Electricity Sector
In his January 2015 inaugural speech, Governor Edmund G. Brown Jr. stated that California
has made impressive progress toward its goal of 33 percent renewable electricity by 2020
and it is time to set new objectives to support the state’s 2050 greenhouse gas (GHG)
emission reduction goals. The Governor proposed increasing the amount of electricity from
renewable sources from one-third to 50 percent by 2030 to help meet the overall goal to
reduce GHG emissions 40 percent below 1990 levels by 2030. 62 The Clean Energy and
Pollution Reduction Act of 2015 (Senate Bill 350, Senator De León, 2015) (SB 350) codifies the
50 percent by 2030 goal for renewable resources.
The president of the California Public Utilities Commission (CPUC), chair of the Energy
Commission, and president and Chief Executive Officer of the California Independent
System Operator (California ISO) pointed to overgeneration, which occurs when too much
electricity is produced at certain times of day when demand is low, as a key challenge as the
state works toward the 50 percent renewable goal. Such challenges, however, foster
innovation. Solutions include a regional marketplace that balances supply and demand,
time-of-use rates that encourage shifts in when consumers use energy, and building
enhancements such as batteries and control systems to better manage energy usage. Also,
research and development will help bring new technologies and other innovations needed
to meet the 2030 and 2050 GHG reduction goals. “More of the same policies will not do the
trick.” 63
This chapter explores issues and opportunities for increasing renewable energy in California
to meet the state’s climate goals. It summarizes California’s current renewable status,
progress toward achieving the actions identified in the 2012 Integrated Energy Policy Report
Update’s (IEPR Update) Renewable Action Plan to support renewable development,
outstanding challenges associated with meeting the Governor’s 50 percent renewable target
by 2030, and possible approaches to better enable the state to meet its goals. While this
chapter is focused on renewable energy, any effort to advance renewables must be part of
an overall portfolio that integrates all demand and supply-side resources across sectors to
reduce GHG emissions, reduce criteria pollutants and meet other environmental goals,
maintain reliability, and control costs.
62 Executive Order B-30-15, https://www.gov.ca.gov/news.php?id=18938.
63 Sacramento Bee. “More Renewable Energy Brings New Challenges,” March 14, 2015,
http://www.sacbee.com/opinion/op-ed/soapbox/article13939937.html.
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Greenhouse Gas Emissions From the Electricity Sector
The electricity sector accounts for about 20 percent of statewide GHG emissions, with about
half from electricity imported from out-of-state, whereas the transportation sector is the
largest source of GHG emissions, accounting for about 37 percent. Consequently, decarbonizing
the transportation sector should be a primary focus of the state’s climate goals,
and policies in the electricity sector must build on policies to reduce emissions from the
transportation sector. For example, new renewable procurement should go hand-in-hand
with increased electric loads from electrification of the transportation sector. If they are not
in lock-step, then California will not realize the full potential of the GHG reduction potential
from decarbonizing the electricity sector.
The electricity sector has made great strides to advance the state’s GHG reduction goals.
According to the California Air Resource Board’s (ARB’s) GHG inventory, electricity sector
emissions in 2013 were already about 20 percent below 1990 emission levels. The Global
Warming Solutions Act of 2006 (Assembly Bill 32, Núñez, Chapter 488, Statutes of 2006) (AB
32) sets a statewide goal to reduce GHG emissions to 1990 levels by 2020. Figure 10 shows
the decline in GHG emissions from the electricity sector.
Figure 10: Historic GHG Emissions From the Electricity Sector
Source: Energy Commission staff using data from the ARB’s 2013 GHG inventory.
In addition to energy efficiency improvements, the reduction in GHG emissions can be
largely attributable to the state’s policies driving increased renewable procurement and
reduced reliance on coal-fired electricity. In the five years from 2008 to 2013 the state has
made remarkable progress in that:
57

• Coal generation dropped by more than half.
• Renewable generation almost doubled.
Decline in Coal-Fired Generation
California’s Emissions Performance Standard has been a driving force behind the state’s
significant reduction in the use of coal, a fossil fuel with high GHG emissions. Senate Bill
1368 (Perata, Chapter 598, Statutes of 2006) created the Emission Performance Standard
setting a maximum emissions rate of 1,100 pounds of carbon dioxide per megawatt-hour
(MWh) for baseload generation—facilities that run most of the time. The Emission
Performance Standard also includes restrictions on capital investments that increase
generating capacity or extend the life of the project. The standard applies to California
publicly owned utilities and the California Department of Water Resources and has resulted
in these organizations ending—or planning to end—contracts and/or ownership with coaland
petcoke-fired generation resources, especially with large out-of-state plants.
Figure 11 shows the decline in the amount of coal-fired electricity serving California from
1996 and over the next decade. In 2014, electricity supplies from existing coal and
petroleum-coke plants represented less than five percent of total energy requirements to
serve California demand, and nearly all of it (93 percent) was from power plants located
outside California. By 2026, virtually all electricity generated by known coal- and
petroleum-coke-fired generation serving California loads is expected to end.
Figure 11: Annual and Expected Energy From Coal Used to Serve California (1996-2026)*
Source: California Energy Commission, CPUC, and ARB presentation at the October 1, 2015, kickoff public workshop on
Scoping Plan Update to Reflect 2030 Target, http://www.arb.ca.gov/cc/scopingplan/meetings/10_1_15slides/2015slides.pdf
*(Includes imports)
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Increase in Renewable Generation
California has a decades-long history of supporting the development of renewable resources
as part of the state’s electricity mix. During Governor Brown’s first administration in the late
1970s, the CPUC established standard offer contracts for alternative electricity suppliers,
including renewable producers, to sell electricity to investor-owned utilities (IOUs) at costbased
rates equal to the buyers’ full avoided cost. By the end of 1991, these contracts added
more than 11,000 megawatts (MW) to the state’s electricity portfolio, about half of which
came from renewable resources. California established a Renewables Portfolio Standard
(RPS) in 2002 to continue to diversify the electricity system and reduce dependence on
natural gas. The original RPS target was 20 percent of retail sales to be met with renewable
resources by 2017, which was subsequently accelerated and expanded to 20 percent by 2010
and then to 33 percent by 2020. Figure 12 shows the growth in renewable generation in
California by resource type from 1983–2014. Overlaid on the graph are some of the policies
that helped spur the market.
There are two periods where generation increases are clearly visible: during the 1980s when
renewable projects came on-line as a result of standard contracts, and then roughly after
2008, when projects procured in response to the RPS came on-line. The increase in
renewable energy generation after 2008 correlates with the decrease in GHG emissions in
the electricity sector.
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Figure 12: California Renewable Energy Generation From 1983-2014 by Resource Type (In-
State and Out-of-State)
Source: California Energy Commission. Tracking Progress webpage. Renewable Energy. Updated September 3, 2015.
Potential Opportunity – Carbon Capture, Utilization, and Storage
Although the state’s strategy to decarbonize the electricity sector is focused on the increased
use of renewable resources, another strategy that may help meet California’s long-term
GHG reduction goals is carbon capture and storage (CCS). CCS technologies have the
potential to reduce the carbon dioxide (CO2) emissions of large point sources by 75–100
percent.
The Energy Commission, ARB, CPUC, and other agencies have been collaborating on CCS
research, rulemaking, and roles definition since they jointly convened a “blue ribbon panel”
on CCS in 2010. 64 The focus of their collaborative efforts has been on jurisdictional and
regulatory issues and the supporting scientific and engineering studies. The ARB is
developing an accounting protocol or “quantification methodology” to allow geologically
stored CO2 to satisfy AB 32 requirements. The protocol, which is scheduled for possible ARB
64 http://www.climatechange.ca.gov/carbon_capture_review_panel/.
60

approval in 2017, may also find use for compliance determinations under the SB 1368
emission performance standard.
Several substantial barriers remain before CCS could be applied to California’s natural gas
generation fleet, including technology developments, optimization studies, pilot facilities,
and private and public investments. Widespread application of the technology would
require additional regulatory and legal frameworks, such as clear, efficient and consistent
regulatory requirements for all phases of CCS such as standards for CO2 capture, transport,
and storage. CCS at natural gas plants is not yet feasible for a number of reasons including
the fact that the captured carbon must be transported to an appropriate geologic storage site
through pipes, for which sites and infrastructure are not readily available. It is also currently
cost-prohibitive, approximately doubling the cost of building a natural gas power plant. In
addition, further technology development is needed to address conditions at many
California power plant locations, such as high summer ambient temperature, the limited
availability of water, and dry cooling and once-through cooling policies, which result in
reduced carbon capture effectiveness and increased parasitic power consumption of the
carbon capture equipment.
The Energy Commission developed a research roadmap to guide its CCS research efforts. 65
The Energy Commission continues to investigate opportunities to reduce the costs and
impacts of CO2 capture for natural gas power plants through emerging capture technologies
that use less energy and water, have a compact site footprint, avoid toxic materials, and
provide load-following capability. Such improvements would largely be applicable to oil
refineries, cement plants, and large biofuels or agricultural processing plants. With respect
to geologic CO2 storage, the Energy Commission is funding geologists to examine changes
in groundwater chemistry in the presence of CO2, the implications of micro-seismic events,
and the risk of larger earth movements at faults. Also important in the overall economics of
CCS is the ability to utilize co-benefits such as using the captured CO2 in enhanced oil
recovery, manufacture of plastics and building materials, biofuels production, and
potentially even the mitigation of other climate change impacts, such as ocean acidification.
65 Burton, Elizabeth, Kevin O’Brien William Bourcier, and Niall Mateer. 2012. Research Roadmap of
Technologies for Carbon Sequestration Alternatives. California Energy Commission. Publication Number:
CEC‐500‐2013‐024. http://www.energy.ca.gov/2013publications/CEC-500-2013-024/CEC-500-2013-
024.pdf.
61

CCS technology demonstration has made progress in the past 2 years, such as commercial
operation of the 110 MW Boundary Dam post-combustion capture project in Saskatchewan
and the saline formation storage project in Decatur, Illinois, passing the million tons injected
mark. Other large-scale CO2 capture projects are expected to reach operational fruition in
2016. Understanding the lessons from these projects will help determine the true
applicability of CCS in the California context.
Renewable Status
Given the Governor’s goal to achieve 50 percent renewables by 2030 to help meet the 2030
GHG reduction goal, this section focuses on the growth of the renewable market in recent
years and progress toward meeting the state’s renewable goals. However, California’s
success in advancing renewable energy extends beyond its borders. Energy Commissioner
David Hochschild emphasized at the May 11, 2015, IEPR workshop on renewable energy
that policies like the RPS have provided the market certainty that has allowed investment to
flow into the clean energy sector and bring down costs. California’s policies are helping
bring technologies to scale for rapid deployment around the nation and the world. 66
When the RPS was established in 2002, there were nearly 7,000 MW of renewable generating
capacity in the state, and renewable generation accounted for about 11 percent of the
electricity mix. 67 As of June 30, 2015, there were more than 21,000 MW of renewable
capacity, and the Energy Commission estimates that nearly 25 percent of 2014 electricity
sales were served by wind, solar, geothermal, biomass, and small hydroelectric resources. 68
California is well on its way to meeting 33 percent renewables. In addition, there are 12,930
MW of new renewable capacity being proposed that have environmental permits and are in
preconstruction or construction, indicating continued interest by renewable project
developers. Proposed solar PV projects account for more than 90 percent of the new
renewable energy capacity expected to come on-line from July 2015 through December
2016. 69 Tracking proposed projects is important for transmission planning, which is
discussed in the next chapter.
The California Solar Initiative, which was established in 2007, has a goal of installing 3,000
MW of solar energy systems on homes and businesses by the end of 2016, along with 585
66 May 11, 2015, workshop transcript, pp. 90-91.
67 California Energy Commission. Renewable Resources Development Report. November 2013.
http://www.energy.ca.gov/reports/2003-11-24_500-03-080F.PDF, p. 29-30.
68 California Energy Commission. Tracking Progress. Renewable Energy.
http://www.energy.ca.gov/renewables/tracking_progress/index.html, pp. 1-2.
69 California Energy Commission. Tracking Progress. Renewable Energy.
http://www.energy.ca.gov/renewables/tracking_progress/index.html, p. 16.
62

million therms of gas-displacing solar hot water systems by the end of 2017. 70 Earlier this
year, California surpassed the 3,000 MW mark, about 1.5 years ahead of target.
There are three parts to the 3,000 MW goal:
1. 1,940 MW for IOUs for commercial buildings and existing homes (including lowincome
programs) as part of the California Solar Initiative.
2. 700 MW for the publicly owned utilities (POUs).
3. 360 MW for IOUs for the New Solar Homes Partnership (NSHP).
As of June 30, 2015, the California Solar Initiative program provided incentives for nearly
1,700 MW of installed capacity and reserved funding for more than 240 MW of pending
capacity toward achieving the goal of 1,940 MW for commercial buildings and existing
residential buildings in IOU service territories. 71 The POUs have installed nearly 320 MW
toward their 700 MW goal as of the end of 2014. 72
The NSHP has seen tremendous growth in recent months. As the housing market recovers
from the crisis of the past few years, builders and homeowners are submitting applications
at a much faster pace to reserve NSHP funding for their projects. As a reference point,
NSHP funding reserved for new home construction projects hit a low of about $9.5 million
in 2009, representing 3.8 MW of installed capacity. By 2014, though incentive levels per
project had dropped, the funding reserved for the year increased to more than $41 million,
representing 30.5 MW. 73 The program design includes lowering incentive levels as the
market grows to help develop a self-sustaining market. Figure 13 shows NSHP program
activity in terms of MW installed from 2007 to 2015.
70 GoSolar California. http://gosolarcalifornia.org/about/index.php.
71 California Energy Commission, Renewable Tracking Progress,
http://www.energy.ca.gov/renewables/tracking_progress/index.html, p. 14.
72 Ibid.
73 Ibid., pp. 13-14.
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Figure 13: Megawatts Installed Solar Capacity for NSHP, 2007–2015
Source: Energy Commission. (January 1, 2015, to August 3, 2015, only)
Progress has also been made toward the Governor’s 12,000 MW distributed generation
(defined here as 20 MW or smaller) target. 74 California has about 6,800 MW of renewable
distributed generation (projects 20 MW or smaller, including both self-generation and
wholesale), with another 1,000 MW in the pipeline, and another 2,400 MW that could be
developed through existing programs. 75 Although the focus of the RPS program has
traditionally been on utility-scale projects, there is increasing interest in the role of
distributed generation in the RPS. Distributed resources produce renewable electricity and
are eligible for the RPS to a limited extent, but, because much of the energy generated is
used on-site rather than being delivered to the grid, questions remain about the appropriate
way to count that generation for RPS compliance.
Investor-Owned Utility Progress
According to the CPUC, as a group California’s three largest IOUs served 22.7 percent of
their 2013 retail electricity sales with renewable power. Table 5 shows RPS procurement in
2013 and the percentage of RPS procurement under contract for 2020. 76
74 A distributed generation system involves small amounts of generation located on a utility's
distribution system for the purpose of meeting local (substation level) peak loads and/or displacing
the need to build additional (or upgrade) local distribution lines.
75 California Energy Commission, Renewable Tracking Progress,
http://www.energy.ca.gov/renewables/tracking_progress/index.html, pp. 13-14.
76 Generation claimed toward IOU obligations for the first RPS compliance period (2011-2013) has
not yet been verified by the Energy Commission.
64

Pacific Gas and Electric
Company
Southern California Edison
Company
San Diego Gas & Electric
Company
Table 5: RPS Progress by Large Investor-Owned Utilities
RPS Procurement %
in 2013
% of RPS Procurement
Currently Under Contract
for 2020
23.8% 31.3%
21.6% 23.5%
23.6% 38.8%
Source: California Public Utilities Commission website, http://www.cpuc.ca.gov/PUC/energy/Renewables/index.htm, accessed
October 5, 2015.
Publicly Owned Utility Progress
The Energy Commission held an IEPR workshop on May 11, 2015, in which representatives
of California’s publicly owned utilities (POUs) provided updates on the status of their RPS
activities.
Los Angeles Department of Water and Power (LADWP) has about 1,400 MW of renewables
in service today, with another 1,256 MW under construction and 2,721 MW planned.
LADWP noted it is on a trajectory to achieve the 33 percent by 2020 RPS targets with added
generation from roughly 2,100 MW of small hydro, wind, solar, and geothermal projects.
Other GHG reduction activities include the utility’s net energy metering program, which
has 15,500 customers, a total of 129 MW installed to date, and $257 million in incentives
paid. LADWP has also set goals for 15 percent energy efficiency, 580,000 electric vehicles by
2030, 500 MW of demand response by 2024, and 154 MW of energy storage planned in the
same time frame. In terms of a 50 percent renewable target, LADWP noted that when it
reaches 33 percent renewables it will need to curtail about 0.2 percent of that energy due to
oversupply; that number rises to 4.6 percent with 50 percent renewables. 77
The Sacramento Municipal Utility District (SMUD) stated that from 2003 to 2014, its
renewable procurement has grown steadily from a distant third to first among POUs in the
state. SMUD emphasized its commitment to a diverse portfolio of renewables, which for
2014 includes biomass, biomethane, geothermal, small hydro, solar, and wind. In the first
RPS compliance period (2011-2013), SMUD reported that it procured enough renewable
energy to exceed the 20 percent target by 3 percent but retired just enough renewable energy
certificates to achieve compliance so as to retain flexibility for future retirement. For the
second and third RPS compliance periods (2014-2016 and 2017-2020), SMUD indicated it
77 May 11, 2015, workshop transcript, comments by John Dennis, Director of Power System Planning
and Development, Los Angeles Department of Water and Power,
http://docketpublic.energy.ca.gov/PublicDocuments/15-IEPR-
06/TN205042_20150616T143227_May_11_2015_IEPR_Workshop_Transcript.pdf, pp. 223-225.
65

expects to reach 27.5 percent and 30 percent, respectively, without counting any carryover it
might have from the first compliance period. SMUD’s focus is on ensuring RPS compliance
for 2020, but it is also positioning itself for future renewable requirements. Like LADWP,
SMUD is looking at a variety of activities related to reducing GHG emissions, including a
pilot biomass gasification project, developing better renewable forecasting models and
evaluating the effect of geographic variation, examining communications capabilities in
photovoltaic inverters, looking at managed charging of electric vehicles, and conducting
demand response pilots. 78
The Southern California Public Power Authority (SCPPA) stated that its members “are
working very hard towards meeting California’s 33 percent RPS target….and should be on
track to meet interim RPS targets through 2020.” 79 SCPPA noted that some members are
exceeding their RPS targets, for example, Pasadena Water and Power and Anaheim Public
Utilities, which respectively were 29 percent and 33 percent renewable in 2014. For a 50
percent renewable target, SCPPA supports a clean energy standard framework to give
utilities the flexibility to meet emissions reduction targets through programs and
technologies best suited for each utility and its customers. SCPPA noted that many of its
members are small and medium-sized utilities that, unlike the larger utilities, are unable to
spread added costs of higher renewables across a wide customer base. In response to
Governor Brown’s 50 percent renewable target, SCPPA recommends ensuring electric grid
reliability, ensuring costs are affordable to California ratepayers, and allowing utilities
maximum flexibility. 80 SCPPA also noted the importance of ensuring that distributed
resources are appropriately valued under the RPS.
The Northern California Power Authority (NCPA) provided several examples of progress
made by its members. 81 The City of Palo Alto anticipates being at 50 percent renewable by
2017 and has a carbon neutral plan that has been in place since 2013. Alameda Municipal
Power and the City of Ukiah have regularly procured more than 50 percent of their energy
from renewable resources. For NCPA’s smallest members, a Request for Proposals for 40
MW of solar has been released. However, NCPA members continue to face challenges due
to the drought and its effect on snowpack and hydroelectric generation. (For more
78 May 11, 2015, workshop transcript, Tim Tutt, Government Affairs Representative, Sacramento
Municipal Utility District, pp. 226-234.
79 May 11, 2015, workshop transcript, Tanya DeRivi, Director of Government Affairs, Southern
California Public Power Authority, pp. 235-241. A list of publicly owned utilities represented by
Southern California Public Power Authority is available at http://www.scppa.org/.
80 Ibid, pp. 235-239.
81 May 11, 2015, workshop transcript, Scott Tomashefsky, Regulatory Affairs Manager, Northern
California Power Authority, pp. 241-254. For a list of Northern California Power Authority members,
see http://www.ncpa.com/.
66

information about the drought and impacts on electricity generation, see Chapter 8.) NCPA
noted that without continued flexibility in RPS requirements for the POUs, it will be
virtually impossible for smaller entities to comply.
The California Municipal Utilities Association (CMUA) noted that many of its members
have had aggressive renewable goals since before the 33 percent RPS was put in place. 82 In
total, CMUA members are meeting the 20 percent RPS target for the first compliance period
(2011-2013). CMUA noted that POUs are looking at the ability to count behind the meter
solar generation and echoed NCPA’s comments on the need for flexibility and avoiding a
one-size-fits-all requirement.
Renewable Action Plan Status
In 2013, the Energy Commission released a Renewable Action Plan as part of the 2012 IEPR
Update. The Renewable Action Plan built on suggested strategies to support renewable
development that were described in a 2011 IEPR subsidiary report titled Renewable Power in
California: Status and Issues. That report was prepared in response to Governor Brown’s
direction in 2010 to the Energy Commission to prepare a plan to “expedite permitting of the
highest priority [renewable] generation and transmission projects.” The intent was to
support investments in renewable energy that would create new jobs and businesses,
increase the state’s energy independence, and protect public health.
The Renewable Power in California: Status and Issues report identified five overarching
strategies to support renewable energy:
1. Identify high-priority areas in the state for renewable development.
2. Evaluate the costs and benefits of renewable projects.
3. Reduce the time and cost of renewable interconnection and integration.
4. Promote incentives for renewables that create in-state jobs and economic benefits.
5. Coordinate state and federal financing and incentive programs for critical stages in the
renewable development continuum, including research, development, demonstration,
precommercialization, and deployment.
These strategies formed the basis for the recommendations in the 2013 Renewable Action
Plan. This section provides an overview of recommendations in the plan on which
California has made the most progress, as well as recommendations needing additional
work. Appendix A provides more detail on the progress made on each recommendation.
82 May 11, 2015, workshop transcript, Tony Andreoni, Director of Regulatory Affairs, California
Municipal Utilities Association, pp. 254-257. For more information about CMUA, see
http://cmua.org/.
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Action Items Showing Most Progress
Recommendations on which California has made significant progress since 2013 include the
following:
• Incorporate distributed renewable energy development zones into local planning
processes: Multiple efforts are underway to support this recommendation.
o
o
o
On July 1, 2015, IOUs submitted distribution resource plans to the CPUC. These
plans identify prime locations for renewable distributed generation and other
distributed resources from the utilities’ perspective, which will help developers
select high-value locations for their projects. 83
IOUs have also posted maps on their websites as part of the Renewable Auction
Mechanism feed-in tariff to assist project developers in determining what areas
on the utility system where capacity for distributed generation (DG) projects may
be available. 84 In addition, the California ISO is undertaking an annual process to
identify available deliverability for distributed generation projects connected to
utility distribution systems. 85
An industry stakeholder initiative called the More Than Smart working group has
been meeting regularly to discuss the role of distributed energy resources 86
(DER) in California’s electricity system planning and operation. The group is
focused on making policy recommendations to enable the development of more
DER through electricity system modernization and integrated system planning.
The working group will build off of the IOUs’ recently filed Distribution
Resource Plans and make policy recommendations beyond what is being
83 California Public Utilities Commission, Distribution Resources Plan Applications (filed July 1,
2015), http://www.cpuc.ca.gov/PUC/energy/drp/. Information on the requirements for the plans is
available at http://www.cpuc.ca.gov/NR/rdonlyres/9F82A335-B13A-4F68-A5DE-
3D4229F8A5E6/0/146374514finalacr.pdf.
84 Pacific Gas and Electricwww.pge.com/en/b2b/energysupply/wholesaleelectricsuppliersolicitation/PVRFO/pvmap/index.pag
e; Southern California Edison: www.sce.com/ram; San Diego Gas & Electrichttp://www.sdge.com/generation-interconnections/interconnection-information-and-map.
85 California Independent System Operator. Resource Adequacy Deliverability for Distributed Generation,
2014-2015 DG Deliverability Assessment Results. February 11, 2015.
http://www.caiso.com/Documents/2015DeliverabilityforDistributedGenerationStudyResultsReport.p
df.
86 DER includes distributed renewable generation resources, energy efficiency, energy storage,
electric vehicles, and demand response technologies.
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considered in the CPUC’s Distribution Resource Plans proceeding. 87 As part of
the CPUC’s proceeding, the working group filed a paper titled More Than Smart:
A Framework to Make the Distribution Grid More Open, Efficient and Resilient. 88
o
Also, the Energy Commission is partnering with Southern California Edison
(SCE) on a Distributed Energy Resource Pilot Study in the San Joaquin Valley to
promote coordinated planning for future growth in distributed resources.
Finally, the Energy Commission has published several reports that identify
location-specific value for distributed generation projects. 89
• Identify preferred areas for distributed generation and utility-scale renewable
development: The most noteworthy progress on this recommendation has been the
Desert Renewable Energy Conservation Plan (DRECP). This effort focused on more than
22.5 million acres in the California deserts with the goal of identifying areas for
renewable development with the least environmental impacts and sensitive areas that
should be protected for conservation. The draft DRECP was released in September 2014.
In March 2015, the Bureau of Land Management, the U.S. Fish and Wildlife Service, the
Energy Commission, and the California Department of Fish and Wildlife announced a
phased approach to finalize the development of the DRECP, starting with completion of
the Bureau of Land Management land use plan amendment which designates
development focus areas and conservation areas on public lands. 90
Other actions to support renewable energy development zones include providing
technical assistance to the San Joaquin Valley Solar convening; 91 development of
87 http://www.cpuc.ca.gov/PUC/energy/drp/.
88 http://morethansmart.org/wp-content/uploads/2015/06/More-Than-Smart-Report-by-GTLG-and-
Caltech-08.11.14.pdf.
89 California Energy Commission consultant reports, Identification of Low-Impact Interconnection Sites
for Wholesale Distributed Photovoltaic Generation Using Energynet® Power System Simulation. December
2011. http://www.energy.ca.gov/2011publications/CEC-200-2011-014/CEC-200-2011-014.pdf.
Integrated Transmission and Distribution Model for Assessment of Distributed Wholesale Photovoltaic
Generation. April 2013. http://www.energy.ca.gov/2013publications/CEC-200-2013-003/CEC-200-2013-
003.pdf.
Distributed Generation Integration Cost Study – Analytical Framework. September 2014.
http://www.energy.ca.gov/2013publications/CEC-200-2013-007/CEC-200-2013-007-REV.pdf.
90 “Public Input Drives Next Steps for Desert Renewable Energy Conservation Plan,” news release,
March 10, 2015, http://www.drecp.org/documents/docs/2015-03-
10_DRECP_Path_Forward_News_Release.pdf.
91 The San Joaquin Solar convening is a stakeholder-led effort to identify least-conflict lands in the
San Joaquin Valley that are suitable for renewable energy development.
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informational geo-spatial tools; the Renewable Energy and Conservation Planning
Grants Program, which is providing more than $5 million to help local jurisdictions
include consideration of renewables in their local policies and ordinances; and the
establishment of the Renewable Energy Transmission Initiative 2.0 which is discussed in
the next chapter.
• Electrifying the transportation system: The focus of the Renewable Action Plan was on
renewable electricity, but it also acknowledged the importance of electrifying
California’s transportation system to meet GHG reduction goals. The plan also
discussed the potential to use “vehicle-to-grid” services to provide grid support and
help integrate renewable electricity, and underscored the importance of transportation
electrification in disadvantaged communities because they can face disproportionate
negative impacts from burning fossil fuels, especially from the transportation sector.
Since the Renewable Action Plan’s adoption in 2013, the Energy Commission’s
Alternative and Renewable Fuel and Vehicle Technology Program has awarded nearly
$40 million for plug-in electric vehicle infrastructure, including charging stations, with
many projects located in environmentally high-risk communities. The program has also
awarded more than $30 million for electric trucks and buses in sensitive port areas,
including manufacturing and assembly facilities. (The benefits of the Alternative and
Renewable Fuel and Vehicle Technology Program are discussed in Chapter 4.)
There has also been progress on improving the link between planning efforts for
renewable energy, the electric distribution system, and zero-emissions vehicles. The
California Statewide Plug-In Electric Vehicle Infrastructure Assessment, published in 2014,
makes recommendations for plug-in vehicle infrastructure planning and provides
guidance to local communities. 92 The Energy Commission has also funded 11 regional
plug-in electric vehicle planning grants to develop regional plans for infrastructure,
streamlining of permitting and inspection processes, building code updates, and
consumer education and outreach.
• Developing protocols for advanced inverters: The Renewable Action Plan emphasized
the need for advanced inverters to successfully integrate and manage increasing
amounts of distributed solar resources on the grid. In January 2013, the Energy
Commission and the CPUC formed the Smart Inverter Working Group which includes
utilities, inverter manufacturers, renewable developers, government, and other
stakeholders. The first phase of the project was to develop recommendations for seven
critical autonomous inverter functions; the resulting recommendations were approved
by the CPUC in 2014 and will be implemented by the IOUs by mid-2016. In the second
phase, the working group focused on inverter communication capabilities, and the
92 California Energy Commission, California Statewide Plug-In Electric Vehicle Infrastructure Assessment,
May 2014, http://www.energy.ca.gov/2014publications/CEC-600-2014-003/CEC-600-2014-003.pdf.
70

CPUC is coordinating with the IOUs to implement the resulting recommendations. The
third phase of the project will consider advanced functions such as the ability to respond
to power pricing signals and to connect or disconnect from the grid upon command.
• Fostering regional solutions to renewable integration: Because regional coordination of
electricity markets allows more efficient and economic sharing of renewable and other
generating resources across a broad geographic area, the Renewable Action Plan
recommended continuing to explore opportunities for an energy imbalance market in
the West. There has been substantial progress on this recommendation. Progress on the
Energy Imbalance Market and developing a more regional grid are discussed in detail
below in the section Renewables and Reliability.
• Providing clear tariffs, rules, and performance requirements for integration services:
The Renewable Action Plan recommended designing clear tariffs, rules, and
performance requirements for integration services to fully leverage automated demand
response, energy storage, and other distributed resources to provide renewable
integration services. Major progress on this recommendation was made in July 2015
with the California ISO’s announcement of approval of rules and processes to enable
distributed energy resources to participate in the wholesale energy market. Smaller
resources can now be bundled by utilities or third parties so they collectively can meet
the half-megawatt minimum requirement for participating in the energy market. 93 Also,
the California ISO is working toward introducing a formal flexible ramping product into
its market system. 94
• Establishing research initiatives to support renewable development: California
continues to be a leader in advancing research and development to support renewable
energy development and use. Since 2010, the Energy Commission has awarded more
than $200 million to projects that support the recommendations in the Renewable Action
Plan in the following areas:
o
$70 million to support existing and colocated renewable technologies, including
projects to reduce installation and maintenance costs; improve reliability and
performance, develop community-scale bioenergy, conduct environmental impact
assessment and mitigation, examine opportunities for synergies from combining
renewable technologies, reduce the cost of distributed photovoltaic, integrate
93 California Independent System Operator, “ISO Board approves gateway to the distributed energy
future,” press release, July 16, 2015,
http://www.caiso.com/Documents/ISOBoardApprovesGatewayToTheDistributedEnergyFuture.pdf.
94 California Independent System Operator,
http://www.caiso.com/Documents/DraftTechnicalAppendix_FlexibleRampingProduct.pdf.
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advanced inverter technologies and smart grid components, and identify strategies
to make bioenergy projects more economic.
o
o
$20 million to bring innovative technologies closer to commercialization, examine
the potential of technologies on the horizon, develop data and tools to support
market facilitation, verify the performance of innovative technologies, and develop
technologies in the areas of biomass conversion, offshore wind, concentrating solar
power, small hydro, and geothermal. Other projects have evaluated strategies to
reduce peak demand, minimize the environmental impacts of energy generation,
and bring technologies to market that provide increased environmental benefits,
greater system reliability, and reduced system costs.
$109 million for projects to integrate intermittent generation; improve solar and
wind forecasting, develop smart grid technologies and microgrids, improve energy
storage technologies, develop grid planning tools, distribution system upgrades, and
demonstration and deployment projects for renewable-based microgrids.
o $9 million to reduce and resolve environmental barriers to renewable deployment;
develop new technology designs, scientific studies, and decision-support tools to
avoid impacts to environmentally sensitive areas and permitting delays; and provide
environmental analysis to support identifying preferred areas for renewable
development, such as the San Joaquin Valley.
Action Items Needing Further Work
Suggested actions in the Renewable Action Plan for which there has been less progress
include:
• Developing renewables on state properties. In 2011, the Energy Commission’s
Developing Renewable Generation on State Property report recommended a goal of 2,500
MW of renewables on state properties by 2020, with interim targets of 833 MW by 2015
and 1,666 MW by 2018. 95 According to the Department of General Services’ Renewable
Energy Directory, there are 43 MW of renewable projects installed on state properties,
with another 8 MW planned, far short of the 833 MW interim goal for 2015. In addition,
the majority of installed and planned projects are less than 1 MW, indicating more focus
may be needed on promoting larger installations going forward to achieve the interim
and long-term targets. In support of this effort, on October 1, 2015, the California State
Lands Commission and the Bureau of Land Management announced a historic
agreement to pursue an exchange of state lands with federal lands. This State Land
Exchange will protect conservation lands and facilitate renewable energy development.
95 California Energy Commission. Developing Renewable Energy on State Property. April 2011.
http://www.energy.ca.gov/2011publications/CEC-150-2011-001/CEC-150-2011-001.pdf.
72

• Improving the transparency of renewable cost information and distribution planning
processes. Improving the ability to track publicly available information on renewable
project costs will expand the state’s understanding of cost trends and drivers in the
growing distributed renewable energy portfolio and help support distribution planning.
California’s energy agencies need to increase efforts to work with the U.S. Energy
Information Administration, utilities, customers, and developers to develop a
framework to prepare transparent estimates of the system costs of renewable distributed
generation. In addition, the Energy Commission needs to coordinate with local, state,
and federal agencies to identify available cost data and what additional information is
needed to support distribution planning.
For more transparent distribution planning, the energy agencies and utilities need to
continue to improve coordination and integration of distributed generation procurement
programs, long-term procurement plans, smart grid deployment plans, and
transmission planning so that the distribution planning process is at least as transparent
as planning processes on the transmission side. The work being done through the “More
Than Smart” working group led by California ISO staff is an important contributor to
this effort. 96
• Instituting workforce development to support the renewable industry: The Renewable
Action Plan emphasized the importance of developing a well-trained workforce to
support California’s renewable policy goals. Strategic partnerships among energy, labor,
and education agencies are needed to ensure that training matches the needs of the
industry. For example, in June 2015 the State of California’s Employment Training Panel
approved more than $300,000 in renewable fuel and vehicle technology job training
funds to train more than 400 workers in the clean technology sector. 97 These kinds of
efforts are needed in the electricity sector as well.
96 The “More Than Smart” working group is an offshoot of the More Than Smart – A Framework to
Make the Distribution Grid More Open, Efficient, and Resilient white paper by Greentech Leadership
Group and Resnick Sustainability Institute, http://greentechleadership.org/wpcontent/uploads/2014/08/More-Than-Smart-Report-by-GTLG-and-Caltech.pdf.
97 State of California Employment Training Panel, “Employment Training Panel Awards $368,280 to
Train Clean/Green Sector Workers in Partnership with the California Energy Commission,” June 26,
2015, http://www.labor.ca.gov/pdf/ETPPressRelease-June2015.pdf.
73

Renewables and Reliability
Success in advancing renewable resources necessarily means facing the challenge of their
variability. To maintain reliability, the grid operator must balance supply and demand. This
becomes more challenging as increasing amounts of solar without storage are deployed,
producing large daily upward and downward ramps in energy generation.
At the May 11, 2015, IEPR workshop, the California ISO noted that the magnitude of
overgeneration due to renewable generation in excess of electricity demand could be as
great as 12,000 MW under a 33 percent RPS. Keith Casey from the California ISO noted that
the California ISO’s analysis showed that under a 40 percent RPS there are times when net
load 98 becomes negative. This means that the California ISO system would not be able to
accommodate all of the renewable generation during that period. 99
An analysis in the CPUC’s Long Term Procurement Planning (LTPP) shows significant
curtailment will be needed in 2024 to maintain grid reliability, assuming today’s RPS rules
apply to a 40 percent renewables target. With a 50 percent RPS, overgeneration will become
increasingly challenging regardless of whether current RPS rules apply. 100
Figure 14 shows the amount of overgeneration expected in calendar year 2024 assuming a
40 percent renewable requirement in a business-as-usual scenario. In this graph,
overgeneration refers to renewable capacity that would have nowhere to go and would be
curtailed in 2024 if business-as-usual continued. Under those conditions, roughly 10 percent
of the year is expected to have some amount of overgeneration. However, tools such as
targeted energy efficiency, demand response, storage (many types), bi-directional electric
vehicle dispatch, electrification of thermal end uses, and hydrogen production for fuel cell
vehicles will likely be deployed to avoid deep and frequent curtailment.
98 A net load curve is total load less the production of wind and solar generating facilities.
99 May 11, 2015, IEPR workshop transcript, p. 161.
100 July 9, 2015, Greenhouse Gas Symposium. presentation by Phil Pettingill, the Director of State
Regulatory Affairs at the California ISO.
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Figure 14: Potential Curtailment in 2024 at 40 Percent Renewables
Source: California ISO
UCS presents a different perspective on overgeneration, suggesting that it can be considered
as failure to curtail natural gas generation, rather than a direct effect of renewables. Figure
15 shows UCS’ version of a net load curve highlighting those hours in the day with excess
generation. Laura Wisland with UCS suggested, “It’s our challenge to figure out how to take
advantage of as much solar as we can, in the middle of the day, when it’s generating. And
then, also bring on additional types of resources to smooth that generation over time and
turn down the gas plants as much as possible, so we’re getting the commensurate
greenhouse gas benefit.” 101
101 May 11, 2015, workshop transcript, p. 169.
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Figure 15: Potential Curtailment Scenario
Source: Laura Wisland’s presentation (UCS) during the May11 Renewable Workshop, see
https://efiling.energy.ca.gov/Lists/DocketLog.aspx?docketnumber=15-IEPR-06.
Many options are available to help manage renewables’ unique characteristics and
increasing scale en route to achieving the state’s climate goals. The discussion below draws
largely from a July 9, 2015, symposium held by the Governor’s office and joint energy
agencies to solicit input on achieving Governor Brown’s 50 percent renewables goal 102 as
well as a May 11, 2015, IEPR workshop on renewable resources.
Pathways Study on GHG Reductions Needed by 2030 to Achieve 2050 Goals
Energy+Environmental Economics (E3) developed a study on GHG reduction levels needed
in 2030 for a pathway to the 2050 GHG reduction goal. 103, 104 The study analyzed a series of
scenarios with different technology combinations and differing paces of emission
reductions. The Pathways study uses a bottoms-up approach to analyze hand-constructed
scenarios, and the scenarios are not optimized to find the least-cost way to reach GHG goals.
It is policy-neutral and provides results showing levels of efficiency, renewables, electric
102 Executive Order B-30-15, http://gov.ca.gov/news.php?id=18938.
103 https://ethree.com/public_projects/energy_principals_study.php.
104 The heads of the California Air Resources Board, Energy Commission, CPUC, and the California
ISO engaged E3 to conduct the study.
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vehicles, demand response, storage, and so forth, and how to combine such resources to
reach a given level of emissions reductions by a given time.
The chief finding is that decarbonizing the California economy depends on four transitions,
with progress needed on each by 2030: 105
• Achieve greater efficiency and conservation in buildings, industry, infrastructure,
water, and the vehicle fleet.
• Switch fuels to increase the share of electricity and hydrogen in the energy mix.
• Decarbonize electricity.
• Decarbonize fuels (liquid and gas).
At the July 9, 2015, symposium, Dr. Nancy Ryan from E3 noted that one central conclusion
is that to realize cost-effective decarbonization, California must use all sources of potential
flexibility, including tight integration of the transportation sector. Increased regional
diversification and resource diversity are critical, and flexible loads will also be important.
She suggested that the study shows that California will still need fast-ramping gas plants
with low minimum generation well into the future. Finally, Dr. Ryan suggested the need to
integrate the energy system across sectors.
Integrated Planning
Taking a more integrated approach to energy planning is a key tool for addressing the
potential challenges associated with increased amounts of renewable resources. If codified,
SB 350 will help address this issue by requiring integrated resource plans for the publicly
owned and investor-owned utilities. The CPUC has already started to look at clean energy
procurement in a comprehensive way. An example is the CPUC’s decision 15-09-022 which
provides a foundation for the integration of distributed energy resources.106 The decision
establishes a framework for distributed energy resources that, “is based on the impact and
interaction of such resources on the grid as a whole, on a customer’s energy usage, and on
the environment” with the goal, “to deploy distributed energy resources that provide
optimal customer and grid benefits, while enabling California to reach its climate
objectives.”
At the July 6, 2015, symposium, there was broad agreement that the traditional, more siloed
approach to energy planning in which renewable energy goals are considered separately
105 The study also looked at a carbon sequestration scenario, this summary focusses on the
renewables goal.
106 CPUC. Decision Adopting an Expanded Scope, a Definition, and a Goal for the Integration of
Distributed Energy Resources. R. 14-10-003. D. 15-09-022. September 17, 2015.
http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M154/K464/154464227.PDF.
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from energy efficiency or storage or demand response goals, for example, does not generate
optimum results. Each area progresses towards its respective goals but they are not
integrated and not necessarily part of an effective strategy to meet climate goals. A more
integrated approach aimed at GHG reductions is needed.
Such an integrated approach should consider a broad array of tools to de-carbonize the grid,
including: a balanced portfolio of renewable technologies, targeted energy efficiency, timeof-use
rates, demand response, storage, and reconfiguring the existing natural gas fleet to
allow for greater operational flexibility such that they are capable of ramping both up and
down. At the symposium parties also suggested that resource diversity needs go beyond a
diversified portfolio for the timing of energy generation to include all reliability services
such as voltage support and other ancillary services.
Also, as noted above, efforts to decarbonize the electricity and transportation sectors must
be integrated together: for example, balancing the optimization of electric vehicle charging
to support grid reliability and meeting a driver’s needs will be key. There are clear benefits
that come with the wide-scale deployment of electric vehicles—including the battery storage
potential that these vehicles offer when plugged into the grid. However, the California ISO,
Energy Commission, CPUC, and utilities acknowledge that there are also technical
challenges that come with the integration of these vehicles. There are several research efforts
underway to advance vehicle-grid integration. At a high level, the research efforts support
the development of open communication protocols that enable two-way communication
between the utility and the vehicle to manage the vehicle battery by charging with excess
generation, and drawing from it when ancillary services, such as frequency regulation, are
needed for grid stability.
At the May 11, 2015, IEPR workshop, Commissioner Hochschild emphasized that policy
makers must anticipate what the electricity sector will look like in the near future and set
policy accordingly. One major anticipated change is the increasing electrification of the
building sector, including smart appliances that can respond to the needs of the grid. Yet
anticipating all the impacts of a rapid evolution of generation towards renewables is
difficult, because some of those impacts are unknowable. 107 Commissioner Andrew
McAllister identified the opportunity to build in flexibility throughout the system, including
on the demand side. Malleable demand can respond to grid conditions, facilitating system
reliability and full utilization of available renewables. Cutting-edge technologies,
particularly low-cost communication technologies, will be important for enabling grid
responsiveness down to the appliance level. 108
107 Ibid., pp. 141-143.
108 Ibid., pp. 145-147.
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At the July 9, 2015, symposium, the SCE representative suggested that the state should
pursue a suite of opportunities to achieve GHG goals while maintaining reliability and
affordability and that those goals should apply to POUs as well as retail sellers. The POU
representatives called for maximum flexibility and to recognize that some POUs are very
small with limited resources and unique circumstances that need to be accounted for in
designing rules for carbon reductions.
California ISO Energy Imbalance Market
An important tool to help integrate renewables into the grid is the California ISO’s real-time
energy imbalance market (EIM). The EIM is a voluntary market for procuring imbalance
energy to balance supply and demand deviations in real time from 15-minute energy
schedules and dispatching least-cost resources every five minutes in the combined network
of the California ISO and EIM Entities. The many benefits of the EIM include reduced costs
for utility customers and California ISO market participants, reduced carbon emissions and
more efficient use and integration of renewable energy, and enhanced reliability through
broader system visibility. PacifiCorp was the first entity to join the EIM. 109 Figure 16 depicts
the existing and future EIM entities, as discussed in more detail below.
Scheduling renewables in smaller time intervals, such as the real time market, can reduce
the amount of reserves needed since the opportunity for differences between forecast and
actual generation is reduced from an hour to a shorter time interval. Germany has been a
leader in advancing renewable energy with renewable resources increasingly serving up to
50 percent of demand on sunny and windy days. A study on behalf of Agora Energiewende
found that “… energy and balancing services markets can be structured to reduce the need
for additional flexibility [by making] them ‘faster.’ Fast energy markets are those in which
the dispatching of system resources takes place as close to real time as possible, and where
dispatch schedules are updated at multiple points throughout the day based on updated
weather forecasts.” 110 Energy Commission Chair Robert B. Weisenmiller stated that a clear
message from a June 2015 meeting between U.S. and German energy experts was that
shorter dispatch periods was key to reducing the amount of reserves needed and for
allowing in variability in the accuracy of forecasts. 111
109 PacifiCorp operates two balancing authorities: Pacific Power in Oregon, Washington and
California; and Rocky Mountain Power in Utah, Wyoming, and Idaho.
110 RAP, Power Market Operations and System Reliability: A contribution to the market design debate in the
Pentalateral Energy Forum, study on behalf of Agora Energiewende, December 2014, p. 24.
111 Symposium on the Governor’s Greenhouse Gas Reduction Goals, July 9, 2015.
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Figure 16: Existing and Future EIM Entities
Source: California ISO, http://www.caiso.com/informed/Pages/CleanGrid/EIMOverview.aspx.
Existing and Future EIM Entities
Since the California ISO and PacifiCorp launched the EIM on November 1, 2014, NV
Energy, Puget Sound Energy, and Arizona Public Service balancing authorities are in the
process of joining the real-time market as EIM entities. On September 18, 2015, Portland
General Electric informed regulators of its intent to explore steps needed to join the
California ISO's EIM due to the reduced resource footprint available among participants in
the Northwest Power Pool initiative. As a result, Portland General Electric will withdraw
from further participation in a market initiative led by the Northwest Power Pool. On
September 24, 2015, Idaho Power Company announced its plan to pursue participation in
the California ISO’s EIM.
EIM Transitional Committee and Governance Structure
The California ISO EIM expansion requires that all participating entities, whether inside or
outside California, are given a voice in the decision-making process. Eight members were
80

appointed by the Board of Governors to the EIM Transitional Committee and were charged
with setting up the Governance structure. Members included market participants, state
regulators, and public interest groups. In addition to PacifiCorp, the California ISO Board of
Governors appointed entities from NV Energy, Puget Sound Energy, and APS. On August
25, 2015, the committee adopted the final proposal that was then approved by the Board of
Governors on September 17, 2015.
The governance structure establishes the EIM Governing body as the primary decisionmaker
on policy initiatives that change EIM-specific market rules and has the key advisory
role on market rules that affect EIM. Each member is financially independent of
stakeholders and works to ensure that the interests of all market participants are
represented. Members will be selected by stakeholder nominating committee and approved
by ISO Board.
Regional Grid
Expanding to a more regional grid is also critical to advancing California’s climate goals
while maintaining reliability and controlling costs. (For more information on developing a
regional grid, see Chapter 3.) At the July 9, 2015, symposium, Carl Zichella, director of
western transmission from the Natural Resources Defense Council emphasized the
importance of regional approaches and the need for more coordinated electrical systems to
help reduce GHG emissions. In particular, Mr. Pettingill emphasized that having a larger,
more regional footprint in which to dispatch resources holds great promise for managing
larger amounts of variable renewables. With a regional market, overgeneration in California
could be used in other parts of the west rather than being curtailed. For example,
California’s midday resources can serve load after sunset in Utah during peak periods.
The study on behalf of Agora Energiewende put it this way “Increasing the size of balancing
control areas reduces the need for more resource flexibility. Larger control areas are
beneficial in any case, but where the share of variable production is significant, the benefit
can be especially large… The benefit derives from three main sources: (1) increasing the size
of the control area reduces the impact of any single system event and affords the control
area authority a more diverse portfolio of resource options with which to maintain system
balance; (2) demand across large geographic areas is generally not well correlated and thus
the natural variability of demand cancels out to some extend; (3) the variability of variable
renewable resources is generally not well correlated over large geographic areas, reducing
the variability of supply.” 112 Mr. Pettingill stated that the CPUC’s LTPP analysis showed
that a regional grid would eliminate curtailment and reduce GHG emissions by 1.1 million
tons per year under a 40 percent PRS by 2024. Westwide coordination at a 50 percent RPS
112 RAP, Power Market Operations and System Reliability: A contribution to the market design debate in the
Pentalateral Energy Forum, study on behalf of Agora Energiewende, December 2014, p. 23.
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would lower carbon emissions by an additional 1.5 million tons per year. 113 Figure 17
translates the overgeneration hours to potential GHG savings if the excess generation could
be used regionally rather than being curtailed. Most of the GHG savings potential occurs
between March and June. PacifiCorp has shown interest in joining the California ISO as a
participating transmission owner rather than continuing to operate as separate balancing
authorities. Operating as a single balancing authority is expected to provide greater
visibility, greater load/resource diversity across the region, and better capability to dispatch
the lowest-cost generation in real time. 114
Figure 17: Potential Regional GHG Reductions With 40 Percent Renewables
Source: California ISO presentation at the July 9 Greenhouse Gas Symposium, see
http://docketpublic.energy.ca.gov/PublicDocuments/15-IEPR-06/TN205457-
3_20150722T101921_California_Climate_STrategy.pdf.
Other Proposed Solutions
Poseidon Water proposed that using excess renewable energy to power the production of
drinking water through desalinization is an opportunity to help meet both energy and water
needs in California. Graham Beatty from Poseidon Water noted that the desalinization
process is energy intensive with electricity use accounting for about 50 percent of the
operating expense. As an example, Mr. Beatty stated that the Carlsbad plant produces 50
113 Symposium on the Governor’s Greenhouse Gas Reduction Goals, July 9, 2015, Comments by Phil
Pettingill with the California ISO.
114 California Energy Commission, Tracking Progress, Resource Flexibility, updated August 19, 2015.
http://www.energy.ca.gov/renewables/tracking_progress/index.html#resource_flexibility.
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million gallons of drinking water per day using 30 MW to 35 MW and has some ability to
store additional water onsite. He stated that desalinization projects can be designed to
quickly ramp up or down as needed to have the capability to use renewable energy that
would otherwise be curtailed. 115 Given the size of the project, this would likely produce on
the order of a few MW of flexible capacity.
Manal Yamout of Advanced Microgrid Solutions suggested another opportunity by
aggregating behind-the-meter electricity-storage units coupled with demand response
products that can be aggregated to the size of a virtual power plant within a local
geographic area. Ms. Yamout noted that the product Advanced Microgrid Solutions offers is
for peak periods, which can avoid the need to develop additional peaker power plants or
transmission upgrades. Further, because of the storage component, Advanced Microgrid
Solutions can offer to increase load at times of surplus. 116
Steven Kelly from Independent Energy Producers Association suggested that too much
capacity or too much generation is not a reliability problem, but rather a management
problem. 117 During times of overgeneration, the price of electricity becomes zero or negative,
which means that California balancing authorities are paying others to take the power. 118
Mr. Kelly notes that real-time prices could push businesses and homeowners in the
California balancing authorities to take advantage of the free power rather than giving it
away outside California. 119 Mr. Kelly also noted that if power plant owners modified their
plants to allow them to run at lower generation levels, they could, but the market signals are
not there to create an incentive for them to do so. 120
SMUD expressed concern with the potential for as much as 3,000 MW of solar photovoltaic
systems to simultaneously go offline in reaction to a disturbance on the grid and stated that
photovoltaic systems built over the next six to seven years must be designed to respond to
grid disturbances in a way that enhance reliability. However, SMUD noted that designing
renewables to provide more services to the grid will likely result in a cost increase. 121
Westland stressed the importance for geographic diversity throughout the state to avoid
overreliance on any one geographic region (and the particular renewable technologies there)
at the expense of other regions and technology types, such as solar development in Central
115 Ibid., pp. 185-187.
116 Ibid., pp. 220-221.
117 Ibid., p. 190.
118 Ibid., p. 191.
119 Ibid., p. 192.
120 Ibid., p.196.
121 Ibid., p. 89.
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California. 122 Westland also stressed the importance of focusing on water use as part of
siting and transmission planning for renewable development. 123
Another potential solution is to convert surplus renewable power to hydrogen gas. 124 This is
a potential long-term strategy that could result in a new supply of renewable hydrogen for
transportation use, as well as an input to the natural gas pipeline system to reduce the
carbon content of natural gas. (See Chapter 6 for discussion on natural gas issues.).
Emerging Technologies
Research and development (R&D) is needed to help develop the new tools, technologies,
and systems that are required to integrate the clean energy infrastructure needed to
contribute to the state’s GHG reduction goals. California’s research investments are
developing renewable energy integration solutions, including increased regional
coordination, diversifying the clean energy portfolio, enabling flexible loads, adding
flexibility and controllability to renewable generators, and demonstrating advanced energy
storage technologies and microgrids. The Energy Commission supports this research
through funding from the Electric Program Investment Charge.
The Energy Commission has funded a number of technologies that are being used to
support a more regional grid, better integrate variable generation and increasingly variable
load, and deploy localized community-scale renewable energy projects and microgrids. For
example, the Energy Commission funded early work on synchrophasors for the Western
Electricity Coordinating Council. Synchrophasors are high-speed, utility data collection
systems that can collect up to 30 samples (of phase angles) per second. This high-resolution
data can show abnormalities in the grid and identify their origin. Synchrophasors are now
deployed throughout the national grid.
As the state increasingly relies on intermittent renewable generation, better forecasting
capabilities are needed. Better forecasting in both longer duration (day ahead) and short
duration (5 minute) would allow grid operators to more effectively balance renewables with
other generation and demand-side resources. Ongoing research projects are working to
implement improved forecasting techniques into the planning and operations of the
California ISO grid and individual microgrids that have a high penetration of variable
renewables.
Microgrids are a tool to integrate distributed energy resources and add resiliency to
locations with critical loads such as military bases, prisons, hospitals, or laboratories, and
can serve as a platform to enable very high penetrations of solar and wind energy.
122 Ibid., pp. 108-111.
123 Ibid., pp. 100-101.
124 Ibid., p. 149.
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Microgrids typically use grid power when the utility grid is stable, but have the capability to
island if the utility grid becomes unstable. Microgrids are capable of firming and controlling
their energy export, including intermittent wind and solar, to the utility grid while
integrating supply- and demand- side controls within the microgrid. These capabilities
allow customers and grid operators the ability to take advantage of the benefits of
coordinating energy efficiency measures, demand response enabling technologies, and
distributed generation. The Energy Commission’s early R&D efforts focused on microgrid
controller design and system configurations and through EPIC the Energy Commission is
focused on taking these advanced designs and configurations and demonstrating their full
value to support commercialization of microgrid systems.
Also, the Energy Commission has funded projects to help communities develop and deploy
localized renewable energy-optimized energy management strategies. These strategies are
designed to enable higher levels of renewable energy with minimal grid impacts by
enabling functions such as peak load reduction, load shifting, and a range of other functions
for the local community and the grid.
Storage is another key technology to help improve the reliability of the grid with increasing
amounts of renewable resources. Further research and economies-of-scale are needed to
help bring down costs. The CPUC established a programmatic market for energy storage in
California and set a 1.3 GW energy storage target for the IOUs to support a 33 percent RPS
by 2020. The Energy Commission’s research and development efforts focus on helping
California achieve the energy storage target with technologies that are safe, reliable, and
cost-effective for IOU ratepayers. Research is also focused on improving technology
performance and identifying optimal locations, sizes, and technology types for specific
energy storage functions.
Technologies that enable demand response also help integrate renewable resources,
especially demand response that can be reliably dispatched and is resource adequate.
Innovative coupling of demand response with other technologies like storage can assure the
grid operator of its capability to shed or call on load when needed, and also assure
customers that their electricity needs will not be compromised.
R&D is also helping advance flexible generation resources that can help fill the gaps and
balance the ramps created by intermittent renewables. Some renewable resources that have
typically been operated as baseload resources, such as geothermal and biomass, may be able
to provide the flexibility needed to maintain grid operations in the face of higher levels of
wind and solar.
The state’s long-term climate laws and goals are driving investments in innovations that
will significantly change how the electric grid is planned and operated. California has
demonstrated that it is possible to power a large economy with lots of clean energy
technologies, like solar and wind, however, higher penetrations of these resources will
require a completely new approach to planning and operating the electric grid. As the state
continues to develop markets to increase investment in clean energy technologies it is
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important to make sure customers and grid operators have the tools and resources they
need to integrate technologies that make the most economic and environmental sense.
Continued R&D is critical to building a smart California grid that is capable of integrating
the clean energy resources that will help power a low carbon economy.
Recommendations
• Pursue a diverse renewables portfolio. Different renewable technologies provide
different benefits and services to the grid. The procurement process should avoid
overreliance on cost alone, rather considering the range of benefits renewables can
provide individually and in aggregate. Strategies to reach 50 percent renewables by 2030
should explicitly address resource diversity.
• The 50 percent renewable goal should be a floor, not a ceiling. To achieve California's
greenhouse emissions reduction targets, studies have indicated that renewables will
likely need to be higher than 50 percent by 2030. State energy planning and procurement
processes should therefore be conducted under the assumption that the 50 percent by
2030 renewable target is a floor, not a ceiling.
• Zero-carbon solutions should maintain system reliability while integrating
renewables. Renewable resources can be combined with supporting technologies such
as demand response and a variety of energy storage options to enable low- or no-carbon
electricity without compromising system reliability. Energy procurement should
therefore consider combinations of desired attributes rather than focusing only on
traditional products such as bulk energy or baseload power.
• Encourage even greater participation in the energy imbalance market. To take
advantage of the benefits of real‐time balancing of load and resources and the regional
diversity in renewable resources, where resources are procured every 15 minutes and
least-cost resources are dispatched every five minutes, the state should continue to
encourage other entities, both in state and out of state, to join the California ISO’s energy
imbalance market.
• Further consideration is needed on the role of distributed resources in the
Renewables Portfolio Standard (RPS). California's RPS Program was designed at a time
when distributed renewable resources represented a tiny percentage of total renewables.
With increasing penetration of customer-side renewables and the inclusion of
distributed resources in the California Independent System Operator wholesale market,
the future role of distributed renewables in the RPS should be carefully evaluated
through a public process such as the California Public Utilities Commission's RPS
proceeding.
• Further work is needed to advance renewables on state property. California has been a
leader in promoting the development and use of renewable resources for decades, yet
the state's public buildings and lands do not yet reflect that commitment. The
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ecommendations in the Developing Renewables on State Property Report should be
revisited and more effort devoted to developing renewables on state properties,
particularly larger-scale projects of 1 megawatt or more.
• Continue to support research and development for renewable resources through the
Electric Program Investment Charge. Emerging renewable technologies can transform
the market by establishing new industries and providing new products and services to
improve the efficiency, cost-effectiveness, and reliability of the low-carbon electricity
system. However, the market seldom provides adequate incentives to develop the
innovative technologies that will be needed in the future. The state should therefore
continue to fund and support the Electric Program Investment Charge to advance new
technologies, strategies, and demonstrations of systems such as microgrids that support
renewable development and deployment.
• Additional research is needed to improve understanding of impacts high penetrations
of renewables have on the energy system. Solar and wind forecasting techniques have
improved by leaps and bounds in recent years, but there is still significant room for
improvement. The ability to accurately predict ramp events, or periods where solar or
wind resources experience a quick drop in output, presents an opportunity to reduce
operating reserve margins, which translates to significant economic savings for energy
users. Furthermore, the impacts of these ramp events on the electricity grid need to be
examined in greater detail.
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CHAPTER 3:
Strategic Transmission Investment Planning
As discussed in the previous chapter, the state is well on its way to meeting the 33 percent
Renewables Portfolio Standard (RPS) by 2020, and is exploring issues and potential
solutions towards achieving an electricity portfolio that is 50 percent renewable by 2030. In
his 2015 inaugural speech, Governor Edmund G. Brown Jr. put forward the 50 percent
renewable goal that Senate Bill 350 (De León, 2015) codifies. Developing the transmission
needed to support increasing amounts of renewable resources will be critical to meeting the
state’s greenhouse gas (GHG) reduction goals of 40 percent below 1990 levels by 2030.
Collaboration among the California Energy Commission, the California Public Utilities
Commission (CPUC), and the California Independent System Operator (California ISO)
with appropriate stakeholder and public input is crucial for ensuring that the most robust,
cost-effective, sustainable, and environmentally responsible energy infrastructure system is
planned consistent with federal, state, tribal, and local mandates and goals. An important
element to attaining this higher level of renewable generation is the continued improvement
in landscape-scale planning tools and the application of these tools to generation and
transmission planning solutions. Such collaboration maximizes the probability that
transmission planning decisions will elicit appropriate transmission projects that can be
permitted in a timely manner. In addition, California needs to continue coordinating with
the rest of the Western Interconnection 125 in generation and transmission planning, system
operations, renewables integration, and energy imbalance market activities to ensure that
California’s policy objectives are achievable.
In 2004, Senate Bill 1565 (Bowen, Chapter 692, Statutes of 2004) directed the Energy
Commission, in consultation with other stakeholders, to adopt a strategic plan for the state’s
electric transmission grid. Subsequently, Senate Bill 1059 (Escutia and Morrow, Chapter 638,
Statutes of 2006) linked transmission planning and permitting by authorizing the Energy
Commission to designate transmission corridor zones on nonfederal lands to allow for the
timely permitting of future high-voltage transmission projects. The statute also required that
any corridor proposed for designation must be consistent with the state's needs and
objectives as identified in the latest adopted strategic transmission investment plan.
This chapter puts forward the Energy Commission’s Strategic Transmission Investment Plan
for the 2015 Integrated Energy Policy Report (2015 IEPR). It describes efforts to integrate
environmental information into renewable energy generation and transmission planning.
125 The Western Interconnection extends from Canada south to Mexico and includes the Canadian
provinces of Alberta and British Columbia, the northern part of Baja, Mexico, and all or portions of 14
Western states (California, Oregon, Washington, Idaho, Montana, Wyoming, Nevada, Utah,
Colorado, Arizona, New Mexico, South Dakota, Nebraska, and Texas).
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The state continues to refine these processes and tools as it works closely with other federal
and state agencies, local governments, and stakeholders to plan for California’s renewable
generation and GHG reduction goals. The chapter also describes in-state and interstate
transmission planning and projects that can help California meet its current and future
renewable generation goals, and opportunities for easing future potential transmission
build-out.
For more information on the state’s renewable energy goals, see Chapter 2, Decarbonizing
the Electricity Sector.
Landscape-Scale Planning Efforts and Analytical Tools
In the 2014 IEPR Update process, the Energy Commission held a workshop on integrating
environmental information in renewable energy planning. This workshop built upon
themes highlighted in several previous IEPRs and IEPR Updates regarding the need to
proactively address environmental and land-use issues to promote renewable project
development, integrate that information into planning and procurement, and coordinate
land-use and transmission planning in the Desert Renewable Energy Conservation Plan
(DRECP) area 126 with the goal of expanding planning to other areas of the state.
Recommendations from the 2014 IEPR Update included the following:
• Finalize and implement the Desert Renewable Energy Conservation Plan.
• Collaborate and improve agency energy infrastructure planning.
• Advance the current capabilities of the state in performing landscape-scale analysis.
• Evaluate how to best apply landscape considerations in statewide transmission plans.
A public workshop for the 2015 IEPR process was held on August 3, 2015, to continue the
discussion in the 2014 IEPR Update of using landscape-scale environmental evaluations for
energy infrastructure planning. The workshop provided a forum to receive information and
updates on various renewable energy and landscape-scale planning activities underway in
California. This workshop included an overview of activities and lessons learned by local
governments that received Renewable Energy Conservation Planning Grants from the
Energy Commission, as well as information on ongoing renewable energy and transmission
planning activities at the CPUC, the California ISO, and the Energy Commission. The
workshop discussion also included an update on the Western Electricity Coordinating
Council (WECC) efforts to identify the environmental risks for regional transmission need
studies.
126 The DRECP area totals roughly 22.5 million acres of federal and nonfederal desert land in
California’s Mojave and Colorado deserts in seven counties: Kern, San Bernardino, Riverside, Inyo,
Imperial, Los Angeles, and San Diego.
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Energy Commission staff presented information on analytical tools and approaches
developed for the DRECP that can be scaled up to support planning efforts beyond the
DRECP area. The experience gained through the DRECP and related renewable energy
planning efforts underscores the importance of using advanced analytical tools to support
landscape planning efforts, through fostering information sharing, collaboration, and
stakeholder and public engagement.
Prior to the above noted workshop, on July 30, 2015, Energy Commission Chair Robert B.
Weisenmiller and CPUC President Michael Picker sent a joint letter to California ISO
President and CEO Stephen Berberich requesting California ISO’s participation in a new
transmission planning initiative, the Renewable Energy Transmission Initiative (RETI) 2.0. 127
This effort would help achieve California’s climate and policy goals and Governor Brown’s
Executive Order, B-30-15, which calls for a 40 percent reduction in GHG emissions below
1990 levels by 2030. An important part of meeting this GHG reduction goal is the
production of at least 50 percent of the state’s electricity from renewable resources.
Update on Ongoing Renewable Energy and Transmission
Planning Efforts
DRECP and Related Planning Efforts
In late 2008, the Energy Commission, California Department of Fish and Wildlife, the U.S.
Bureau of Land Management (BLM), and the U. S. Fish and Wildlife Services signed a
memorandum of understanding (MOU) 128 formalizing the Renewable Energy Action Team
(REAT) for expediting the development of renewable energy resources in California’s desert
region to help meet the state’s renewable energy goals.
These agencies developed the DRECP, a landscape-scale, multi-agency, science-based
renewable energy and conservation plan covering 22.5 million acres in California’s desert.
The DRECP sought to identify the most appropriate areas for renewable energy
development and related transmission projects while conserving important biological and
natural resources. Through more than 70 public meetings, the DRECP team worked closely
with local agencies, conservation and environmental groups, the public, tribes, and other
interested stakeholders. The Draft DRECP was released in September 2014, and the public
comment period ended in February 2015. The agencies received nearly 12,000 comments
during the comment period.
127 http://www.energy.ca.gov/reti/reti2/documents/2015-07-
30_Letter_to_CAISO_RE_RETI_2_Initiative_from_CEC_and_CPUC.pdf.
128 http://www.energy.ca.gov/siting/2008-11-17_MOU_CEC_DFG.PDF.
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In March 2015, the REAT agencies announced that the DRECP planning process would
move forward in a phased manner. 129 Phase I is focused on completing a BLM Land Use
Plan Amendment for the DRECP area. The land use plan amendment will amend existing
land designations to create areas for both energy development and conservation areas on
public federal lands. The BLM land use plan amendment and final environmental impact
statement (EIS) are expected to be released in late 2015.
Phasing the DRECP had the benefit of providing additional time for the counties that
received Renewable Energy and Conservation Planning Grants to complete their planning.
Counties have land use and permitting authority for most projects on private land, and
counties are key partners in meeting the state’s renewable energy and conservation goals.
Phase II of DRECP will explore better alignment of renewable energy development and
conservation goals and policies at the local, state, and federal levels, including opportunities
for a tailored county-by-county approach that supports the overall set of renewable energy
and conservation goals in the DRECP area.
Coordination with Federal Section 368 Corridors
Section 368 of the Energy Policy Act of 2005 required the U.S. Department of Energy (DOE),
the BLM, and the U.S. Forest Service (USFS), in cooperation with the departments of
Agriculture, Commerce, Defense, and Interior, to designate new right‐of‐way corridors on
western federal lands for electricity transmission, distribution facilities, and oil, gas, and
hydrogen pipelines. The DOE, BLM, and USFS prepared a West‐Wide Energy Corridor
Programmatic Environmental Impact Statement that evaluated issues associated with the
designation of energy corridors on federal lands in 11 Western states. 130 In late 2005, BLM
designated the Energy Commission as a cooperating agency, and thereafter in coordination
with DOE, BLM, and USFS, the Energy Commission established an interagency team 131 of
federal and state agencies to review proposals to designate new and/or expand existing
energy corridors and examine alternatives on California’s federal lands. In 2009, the
corridors were designated by BLM and USFS. Thereafter, multiple organizations filed a
lawsuit against the U.S. Department of the Interior. 132 In 2012, a settlement agreement
129 http://drecp.org/documents/docs/2015-03-10_DRECP_Path_Forward_News_Release.pdf.
130 For more information, see http://energy.gov/oe/services/electricity-policy-coordination-andimplementation/transmission-planning/energy.
131 State agencies on this interagency team include the California Department of Fish and Wildlife,
the Native American Heritage Commission, the CPUC, and the Governor’s Office of Planning and
Research. In addition, the State Lands Commission and the Department of Parks and Recreation have
provided input and been monitoring the interagency team’s activities. Federal agencies actively
involved include the USFS, the National Park Service, the U.S. Air Force, the U.S. Marine Corps, and
other Department of Defense services.
132 See: Wilderness Society, et al. v. United States Department of the Interior, et al., No. 3:09-cv-03048-JW
(N.D. Cal.).
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equired the agencies to complete a corridor study and periodically review designated
corridors. 133 A 2013 Presidential Memorandum also required the Secretaries to undertake a
continuing effort to identify and designate energy corridors.
BLM is in the early stages of reviewing corridors for possible additions, deletions, or
modifications in Western Arizona, Southern Nevada, and Southern California. The Energy
Commission will work closely with BLM in its evaluation of corridors and coordinate that
activity with RETI 2.0 and other planning processes.
Electricity Infrastructure Planning Processes
Since the formation of the original RETI 134 and DRECP, the Energy Commission, CPUC, and
California ISO have recognized the value of collaborating to align their electricity
infrastructure planning with the primary goal of ensuring that California’s energy and
environmental policies are met in a coordinated, transparent, and effective manner. The
alignment process has helped ensure that a consistent set of technical assumptions are used
and applied by the three agencies to establish the analytical link among the different
infrastructure studies. The coordinated agency planning activities have become more critical
as higher levels of renewable generation capacity are expected to be developed for
California.
The Energy Commission collaborated with the CPUC to develop the environmental scoring
metric that has been an input to the RPS Calculator for developing scenarios of renewable
generation projects. The RPS Calculator is a screening tool, developed by E3 Consulting 135
for the CPUC to sort the potential renewable generation projects identified by the CPUC
and the Energy Commission into supply curves using different evaluation criteria (project
costs or environmental scores, for example). The calculator ultimately identifies a set of
renewable project portfolios for procurement evaluations that are transmitted to the
California ISO for their transmission need studies. The CPUC and Energy Commission are
in close cooperation as the RPS Calculator is being redesigned and updated within the
current RPS proceeding at the CPUC (Rulemaking 15-02-020).
The Western Electricity Coordinating Council (WECC) is a nonprofit organization dedicated
to assuring a reliable bulk electric system in the geographic area known as the Western
Interconnection. WECC developed a four-tier environmental risk classification system for
assessing the likelihood that a transmission project developer might encounter
133 The settlement agreement is located at
http://corridoreis.anl.gov/documents/docs/Settlement_Agreement_Package.pdf.
134 RETI was initiated in 2007 as a joint effort among the Energy Commission, CPUC, California ISO,
utilities, and other stakeholders. See chapter discussion below for more information.
135 E3 first developed the RPS Calculator to support the CPUC’s 33 percent RPS Implementation
Analysis. https://ethree.com/public_projects/rps.php.
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environmental risks in the development process. 136 These environmental risk metrics will
simplify evaluation of transmission options, together with information on capital cost,
reliability, and engineering. The Energy Commission will work with the WECC and
stakeholders on how to best incorporate these regional environmental metrics with
statewide energy infrastructure planning.
Further work is needed to better characterize the environmental implications of proposed
renewable generation and transmission projects throughout California and in other Western
regions. The Energy Commission continues to investigate environmental information
sources developed for different landscape-level studies and consider geographic
information system (GIS) mapping tools for energy stakeholder planning evaluations. The
Energy Commission supports the inclusion of environmental information in the interagency
planning processes.
Local Government Planning Activities
California county governments are the permitting authority for most nonthermal power
plants, such as wind and solar photovoltaic, located on private lands in California. Projects
approved by counties are subject to applicable federal and state law, as well as local
governments’ land-use rules and policies. Counties, especially those rich with renewable
energy resources, play an integral role in siting projects and helping California meet its
energy and environmental goals.
Kern County, for example, adopted a Renewable Energy Goal of 10,000 MW of permitted
capacity by 2015. The County has permitted 9,723 MW and has an additional 270 MW under
review. The benefits to the County and the state from this renewable development include
8,000 construction jobs, 1,500 operational jobs, $25 billion of direct investment, $50 million in
new property tax revenue, more than $25 million in sales tax, and power production for
more than 7 million people. 137 Butte County implemented PowerButte in May 2015. This
initiative is intended to encourage renewable energy, support the County’s General Plan
and Climate Action Plan, and help meet county and state GHG reduction targets and
renewable energy goals. As part of the initiative, the County is working closely with the
public and stakeholders to identify appropriate areas within the county for the development
136 Risk class 1 encompasses the lowest risk of environmental sensitivities and represents preferred
areas for transmission development, such as existing transmission rights-of-way. Risk classes 2 and 3
have low-to-medium and high risks of environmental sensitivities, respectively, and a likelihood of
mitigation requirements. Risk class 4 includes exclusion areas where transmission development is
precluded by legislation or regulatory restrictions.
137 See the Energy Commission Docket Log, 15-IEPR-08 (Transmission and Landscape Scale
Planning), Transaction Number 205564, available at
https://efiling.energy.ca.gov/Lists/DocketLog.aspx?docketnumber=15-IEPR-08.
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of solar energy facilities, as well as identifying farmland and natural resources that should
be protected.
Most local governments face staffing and other resource challenges that affect their ability to
plan adequately for renewable energy development in their jurisdictions. To help address
these challenges, Governor Brown signed Assembly Bill X1 13 (V. Manuel Pérez, Chapter 10,
Statutes of 2011), which authorized the Energy Commission to award up to $7 million in
grants to “qualified counties” to develop or revise rules and policies that promote the
development of eligible renewable energy resources, the associated transmission facilities,
and the processing of permits for eligible renewable energy resources. “Qualified counties”
identified in AB X1 13 are Fresno, Imperial, Inyo, Kern, Kings, Los Angeles, Madera,
Merced, Riverside, San Bernardino, San Diego, San Joaquin, Stanislaus, and Tulare. In 2012,
Assembly Bill 2161 (Achadjian, Chapter 250, Statutes of 2012) added San Luis Obispo county
as a qualified county.
To implement AB X1 13, the Energy Commission established the Renewable Energy and
Conservation Planning Grants (RECPG) in 2012 and awarded more than $5 million out of
the available $7 million. RECPG helps qualified counties update their general plans and
zoning codes, complete environmental studies and mitigation plans, and engage the public.
Grants also help ensure that county land-use plans are consistent with federal and state
goals for renewable resource development and natural resource conservation.
The Energy Commission held competitive solicitations to award RECPG funding in
February 2013, January 2014, and February 2014 and approved grant awards to Imperial,
Inyo, Los Angeles, Riverside, San Bernardino, and San Luis Obispo Counties. Activities
funded by the grants include development of renewable energy elements as part of
counties’ general plan updates, preparation and certification of environmental impact
reports, identification of areas within a county where renewable resources will be given
priority and be eligible for streamlined permitting, collection and development of data, and
engagement of public, private, and tribal partners to plan for renewable energy
development. The work funded by RECPG grants represents important steps toward
achieving California’s long-term GHG reduction, energy, and natural resource conservation
goals.
As California moves to implement the 50 percent RPS by 2030 requirement, the state expects
to see additional renewable energy development in California. Local governments have
permitted many of the renewable energy projects that are contributing to meeting the 33
percent RPS, and will continue to be important partners in permitting and planning going
forward. The state should consider providing additional renewable energy and
conservation planning grants to California counties where a significant amount of
renewable development may be anticipated. In addition, the Energy Commission should
develop and provide fact-based educational materials to counties and the public on
renewable energy to help promote planning activities and public outreach.
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Planning with Stakeholders for Solar Development on Least-
Conflict Lands in the San Joaquin Valley
Over the last several years, the San Joaquin Valley has experienced a significant increase in
the number of solar projects under development to meet the state’s 33 percent RPS
requirement. The area is appropriate for solar development because of its abundant
sunshine and hot, dry climate. However, the region is also one of California’s most
important agricultural production areas, as well as home to several important species and
habitat areas. A variety of stakeholders have expressed concern over continued solar
development and the associated potential impact to both agricultural areas and sensitive
habitats. In addition, there is a continued shortage of available water for irrigation needs
and long-standing issues associated with the natural buildup of selenium and other
chemicals on drainage-impaired agricultural lands and the retirement of impacted lands
from agricultural production.
In June 2015, the Governor’s Office of Planning and Research launched a stakeholder-led
process to identify “least-conflict” lands in the San Joaquin Valley for solar development
and provide input to policy makers for eliminating barriers to siting projects on those leastconflict
areas. Using the best available data and information, stakeholder work groups, for
example, agriculture (rangeland and farmland), conservation, transmission, solar industry,
and others, identified and mapped a set of least-conflict lands for solar development. State
and federal agencies provided data and technical assistance to the workgroups.
Once the work groups agreed to least conflict areas, a preliminary evaluation of existing
transmission facilities and already-approved transmission projects began. Transmission
planners from SCE, PG&E, and the California ISO have begun discussions and believe that
available capacity on the current transmission system, including projects already in
progress, ranges between 2,000 MW to 3,000 MW. This effort, relying on previous studies,
identified existing transmission facilities in the area and current system constraints. A final
report on this project is expected in October 2015. The data and stakeholder work product
produced in the San Joaquin Valley study will provide an input into RETI 2.0.
Renewable Energy Transmission Initiatives
RETI
The Renewable Energy Transmission Initiative (RETI) was initiated in June 2007 to (1) help
identify the transmission projects needed to accommodate California’s renewable energy
goals, (2) ease the designation of corridors for future transmission line development, and (3)
expedite transmission line and renewable generation siting and permitting. Using a
collaborative analytical effort, RETI stakeholders identified 31 competitive renewable
energy zones throughout the state. These competitive renewable energy zones were the
geographical areas that were the most favorable for cost‐effective and environmentally
responsible renewable generation development with corresponding transmission
interconnections and lines. The competitive renewable energy zones included about 80,000
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MW of potential statewide renewable resource development, with nearly 66,000 MW of the
potential located in California’s Mojave and Colorado Deserts.
RETI established a precedent for taking a landscape-scale planning approach to renewable
energy and transmission planning by bringing together state, federal, and local agencies and
a diverse group of stakeholders. The stakeholders worked together toward a common goal
of helping the state achieve important renewable energy goals. 138
RETI 2.0
As noted earlier, on July 30, 2015, Energy Commission Chair Robert B. Weisenmiller and
CPUC President Michael Picker sent a joint letter to California ISO President and CEO
Stephen Berberich noting their intent to establish the RETI 2.0 and requesting that California
ISO join the effort. RETI 2.0 is intended to help achieve the state’s current climate and policy
goals, including a reduction in GHG emissions to 40 percent below 1990 levels by 2030 and
further reductions to 80 percent below 1990 levels by 2050.
As noted by Chair Weisenmiller and President Picker, it is important to ensure that the RETI
2.0 process is inclusive and transparent to promote robust stakeholder engagement in this
process. The result of this process will be to inform the Energy Commission, CPUC,
California ISO, and other participating public agencies and balancing authorities in their
post-2020 transmission planning.
Landscape-Scale Planning Conclusions
Landscape-scale planning for renewable energy and transmission has proven to be an
important part of meeting California’s renewable energy and climate goals. From the first
RETI process to the joint REAT agency work on the DRECP and the stakeholder-led San
Joaquin Solar process, California agencies, local governments, tribes and stakeholders have
become increasingly familiar with planning approaches that seek to identify the best areas
for renewable energy development. These approaches take into consideration a wide range
of potential constraints and conflicts including environmental sensitivity, agricultural and
other land uses, tribal cultural resources, and more. As noted in the letter by Chair
Weisenmiller and President Picker, there is proven value in using this approach to assess
the relative potential of different locations for renewable energy, especially in the context of
identifying policy-driven transmission lines.
In the time that has ensued since the first RETI process, California has made tremendous
strides in achieving its renewable energy goals. A record number of new renewable energy
projects have been built in California, and California is on track to exceed the 33 percent RPS
requirement by 2020. This experience in planning for and permitting renewable energy
generation and transmission projects, along with the strong relationship among agencies
138 For more information on RETI see http://www.energy.ca.gov/reti/.
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that have worked together to help achieve these goals, will be an important asset to the state
in the RETI 2.0 process and, more broadly, in achieving the 50 percent renewable
requirement by 2030.
Incorporating Landscape-Scale Planning into Transmission
Planning Processes
As noted in previous IEPR cycles, transmission planning processes need to be streamlined
and coordinated to ensure siting, permitting, and construction of the most appropriate
transmission projects to connect renewable resources while ensuring proper consideration
of land-use and environmental issues. In many cases, the project development process that
identifies routing issues and constraints does not begin until after the “wires” planning
process is complete. This lengthens transmission development and increases the risk of
approved transmission projects not being developed due to environmental issues.
As discussed above, the RETI was a statewide land-use planning process to help identify
transmission projects needed to meet the state’s 33 percent RPS by 2020 requirement. This
established the precedent for using landscape-level approaches in renewable energy and
transmission planning and led directly to the collaborative land-use planning occurring in
the DRECP process. In addition, the California Transmission Planning Group, 139 formed in
2009, addressed California’s transmission needs in a coordinated manner by developing a
conceptual statewide transmission plan that identified the necessary transmission
infrastructure to meet the state’s 33-percent-RPS-by-2020 requirement. In December 2010,
FERC approved the California ISO’s revised transmission planning process that requires the
development of an annual conceptual statewide transmission plan, thereby replacing the
California Transmission Planning Group’s planning function.
The lessons of these past collaborations have been incorporated into a planning alignment
process among the Energy Commission, CPUC, and California ISO for evaluating and
approving new transmission system projects. To date, the transmission projects that are
needed to support achievement of California's 33 percent RPS are already approved and
operating or progressing through the CPUC approval process, as discussed below.
Looking forward, the RETI 2.0 process will provide a non-regulatory, stakeholder process to
consider possible scenarios and strategies for meeting California’s 2030 goals which will
139 The formation of the California Transmission Planning Group was an outcome of RETI’s
recognition that detailed transmission planning was needed. The California Transmission Planning
Group conducted joint transmission planning and coordination to meet California’s transmission
needs, and was composed of all entities within California responsible for transmission planning.
RETI and other stakeholders provided feedback and input into the California Transmission Planning
Group’s conceptual statewide transmission plan.
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help inform the possible identification of new policy-driven 140 transmission based on 2030
renewable energy portfolios in the fall of 2016.
California ISO Transmission Planning
A core responsibility of the California ISO is to identify upgrades needed to maintain grid
reliability, successfully meet California’s policy goals, and bring economic benefits to
consumers through an annual stakeholder transmission planning process. Below is an
update on the highest priority approved transmission projects and potential backup
transmission solutions identified in the two most recent annual California ISO Transmission
Plans. 141
2013-2014 Transmission Planning Process
The focus of the 2013-2014 transmission planning process was to identify transmission
solutions to address grid reliability in the Los Angeles (L.A.) Basin and San Diego areas in
light of SCE’s June 7, 2013, decision to retire the San Onofre Nuclear Generating Station (San
Onofre), along with the enforcement timeline of once-through cooling (OTC) regulations for
retiring power plants using ocean or estuarine water for cooling. (This is discussed in detail
in Chapter 7, Electricity Infrastructure in Southern California.) The California ISO conducted an
analysis of the bulk transmission system in light of these changes. As a result, it
subsequently received several transmission proposals in the 2013 request window. The
California ISO grouped the proposals into three categories:
• Group I – transmission upgrades that optimize the use of existing transmission lines and
do not require new transmission rights-of-way. Projects include:
○
○
○
San Luis Rey Substation to provide dynamic reactive support. Expected in-service
date: 2017.
Imperial Valley Substation Flow Controller to help address voltage instability
concerns. Expected in-service date: 2017.
Mesa Substation 500 kilovolt (kV) Loop-In that allows SCE to bring a new 500 kV
electric service into its metropolitan load center, delivering power from Tehachapi
wind resources area or resources located in PG&E’s service territory or the
Northwest via the 500 kV bulk transmission system. Expected in-service date: 2020.
140 In 2010, the California ISO revised its transmission planning process to include a transmission
category for evaluating and approving policy-driven transmission additions and upgrades to support
the state’s policy objectives. Beginning with the 2010-2011 Transmission Plan, the California ISO
focused on the state’s 33 percent RPS requirement for identifying and approving policy-driven
transmission additions and upgrades.
141 For more information, please refer to
http://www.caiso.com/planning/Pages/TransmissionPlanning/Default.aspx.
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• Group II – transmission lines that strengthen the LA/San Diego connection and upgrade
existing corridors. Conceptual projects include:
○
○
○
Talega-Escondido/Valley-Serrano to new Case Springs 500 kV transmission line
High Voltage DC submarine cable from Alamitos to four termination options:
Encina, San Onofre, Peñasquitos, or Bay Boulevard (Chula Vista)
Valley-Inland 500 kV transmission line
• Group III – new transmission into the greater L.A. Basin/San Diego area. Conceptual
project includes:
○
Imperial Valley-Inland 500 kV transmission line
For the 2013-2014 Transmission Plan, the California ISO took a least-regrets approach 142 and
approved Group I projects that reduced the local capacity requirements (LCR), 143 provided
the best use of existing transmission lines and rights-of-way, and minimized the permitting
risk. The California ISO also recommended further analysis of Groups II and III in future
planning cycles with input from state and federal agencies and stakeholders. In addition,
the California ISO approved two interregional economic projects with reliability and policy
benefits: Delaney-Colorado River and Harry Allen-Eldorado. See the section below on
transmission status updates for more information.
High-level Environmental Assessment for the Transmission Planning Process
As discussed above, in its 2013-2014 Transmission Plan, the California ISO identified several
transmission projects that could alleviate the transfer limitations and reliability problems
caused by the shutdown of San Onofre. At the request of the California ISO, the Energy
Commission funded a consultant report that provides a high‐level assessment of the
environmental feasibility of several electric transmission alternatives under consideration by
the California ISO to address reliability and other system challenges resulting from the San
142 This least regrets approach is based on balancing the two objectives of minimizing the risk of
constructing under-utilized transmission capacity while ensuring that transmission needed to meet
policy goals is built in a timely manner.
143 Local capacity requirements refer to the amount of generating capacity required within a local
capacity area. Local capacity areas are transmission-constrained areas, which are identified when the
maximum combined import capacity across the set of transmission line segments between pairs of
substations defining a region is less than the peak load within the region. To serve load reliably, each
local capacity area must have enough generation located within the local area to meet peak load, less
the maximum import capacity of the transmission lines connecting that area to the high-voltage
transmission system. For more information, see Chapter 7.
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Onofre closure. 144 Since the May 2014 publication of the consultant report, the California ISO
found that the closure of San Onofre significantly reduced the capability of the transmission
system to deliver future renewable generation from Imperial County due to changes in
electricity flow patterns over the electric transmission system. To develop a comprehensive
list of potential transmission solutions, the California ISO conducted an Imperial County
Transmission Consultation 145 meeting in July 2014 to provide opportunities for stakeholder
input on issues surrounding the deliverability from the Imperial County area to the
California ISO’s balancing area. In September 2014, following that meeting, an addendum to
the consultant report 146 was prepared that evaluated two additional transmission
alternatives proposed by IID and SCE. A second addendum 147 was prepared in January 2015
that includes additional transmission alternatives suggested in the consultation workshop.
As noted in the 2014 IEPR Update, “One or more of the alternatives may be considered by
Energy Commission staff in the state’s electric transmission corridor designation process.” 148
2014-2015 Transmission Planning Process
The California ISO focused on analyzing potential backup transmission solutions that could
address both a resource development shortfall in the L.A. Basin/San Diego area and provide
additional transmission deliverability for higher levels of renewable generation from the
Imperial County area as recommended in the 2013-2014 planning cycle. The California ISO
developed a list of potential transmission options based on input from the consultation
meetings and projects previously submitted in its request window. The California ISO
developed the final list of projects to analyze based on scope of work, estimated potential
144 Aspen Environmental Group. 2014. Transmission Options and Potential Corridor Designations in
Southern California in Response to Closure of San Onofre Nuclear Generating Stations (SONGS):
Environmental Feasibility Analysis. CEC-700-2014-002 Consultant Report, May 2014.
http://www.energy.ca.gov/2014publications/CEC-700-2014-002/CEC-700-2014-002.pdf.
145 The Imperial County Transmission Consultation process can be found at
http://www.caiso.com/planning/Pages/TransmissionPlanning/2014-
2015TransmissionPlanningProcess.aspx.
146 Aspen Environmental Group. 2014. Addendum to Transmission Options and Potential Corridor
Designations in Southern California in Response to Closure of San Onofre Nuclear Generating Stations
(SONGS): Environmental Feasibility Analysis. CEC-700-2014-002-AD Consultant Report, September
2014. http://www.energy.ca.gov/2014publications/CEC-700-2014-002/CEC-700-2014-002-AD.pdf.
147 Aspen Environmental Group. 2015. Second Addendum to Transmission Options and Potential Corridor
Designations in Southern California in Response to Closure of San Onofre Nuclear Generating Stations
(SONGS): Environmental Feasibility Analysis. CEC-700-2014-002-AD2 Consultant Report, January 2015.
http://www.energy.ca.gov/2014publications/CEC-700-2014-002/CEC-700-2014-002-AD2.pdf.
148 California Energy Commission. 2015. 2014 Integrated Energy Policy Report Update. Publication
Number: CEC-100-2014-001-CMF. http://www.energy.ca.gov/2014publications/CEC-100-2014-
001/CEC-100-2014-001-CMF-small.pdf, p. 153.
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LCR benefits, deliverability of higher levels of renewable generation from the Imperial
County area, preliminary environmental assessments provided by the Energy Commission
consultant reports, and high-level cost estimates. 149 The list of transmission solutions
include:
• IID Strategic Transmission Expansion Plan (Hoober—San Onofre): 180-mile 500 kV DC
line.
• IID Midway-Inland: 125-mile 500 kV DC or AC line.
• Comisión Federal de Electricidad-California ISO Tie and Miguel-Encina (Option A):
combined 102-mile 500 kV AC line and 94-mile underground/submarine 500 kV DC line.
• Comisión Federal de Electricidad-California ISO Tie and Miguel-Huntington Beach DC
Line (Option B): combination of a 102-mile 500 kV AC line and a 148-mile 500 kV bipole
DC line.
• Comisión Federal de Electricidad-California ISO Tie and Laguna Bell Corridor Special
Protection Scheme (Phase 1) and Miguel-Huntington Beach (Phase 2) – Option C:
combination of 102-mile 500 kV AC line and 148-mile 500 kV DC line.
• Talega-Escondido/Valley-Serrano Interconnect: 32 mile 500 kV AC line.
The California ISO’s assessment found the two best backup options addressing a potential
resource development shortfall in the L.A. Basin/San Diego area and providing additional
transmission deliverability for potentially higher levels of renewable generation from the
Imperial County area were the following:
• Comisión Federal de Electricidad-California ISO Tie Line Option C, Phase 1
○
○
If siting is viable in northern Mexico
Provides lowest cost and high LCR reduction benefits
• IID Midway-Inland
○
○
Provides best balance of the options considered – LCR reduction, Imperial County
renewable deliverability benefits, siting viability, and cost
Provides most flexibility to stage components to meet the two needs
149 See California ISO 2014-2015 Board of Governors Approved Transmission Plan, Tables 2.6-8 and 2.6-9,
pp. 103 and 106-109 for more detail. http://www.caiso.com/Documents/Board-Approved2014-
2015TransmissionPlan.pdf.
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The California ISO noted the alternatives involve challenging rights-of-way and lengthy
permitting and construction timelines. Continued analysis will be required as needs evolve
in future planning cycles.
California ISO Participation in RETI 2.0
The recent changes to energy policy goals as outlined in Governor Brown’s Executive Order
B-30-15, along with improved generation and demand-side technologies, evolving
challenges to integrating new intermittent generation, and the need to maintain electricity
system reliability, require periodic updates for renewed, broad, and coordinated attention to
transmission planning in California and the Western Interconnection. As a result, the
California ISO is participating in the newly formed RETI 2.0 that could help inform its
future transmission planning cycles.
Update to Transmission Projects to Meet the 2020 RPS
As noted in the 2013 IEPR, the California ISO, the Imperial Irrigation District (IID), and the
Los Angeles Department of Water and Power (LADWP) identified and approved 17
transmission projects for the integration of renewable resources to enable California to meet
the 33 percent RPS by 2020 requirement. Fifteen of the projects are within the California
ISO’s control area, one project (Path 42) is within both the California ISO’s and IID’s control
area, and one project is within LADWP’s control area. As noted above, in the 2013-2014
Transmission Plan, the California ISO identified two interregional projects, Delaney-
Colorado River and Harry Allen-Eldorado, as economic projects with reliability and policy
benefits. In May 2015, the CPUC determined that the Coolwater-Lugo transmission project
was no longer needed and dismissed the application without prejudice. Below is an update
of the projects presented according to their associated actual or expected on-line date.
2011 Projects
Midway-Bannister: On March 15, 2011, the IID completed and energized the 8.7-mile 230
kV transmission project.
2012 Projects
Sunrise Powerlink: On June 17, 2012, San Diego Gas & Electric (SDG&E) completed and
energized the 117-mile 230/500 kV transmission project.
2013 Projects
Colorado River-Valley: On September 29, 2013, Southern California Edison (SCE)
completed and energized the 153-mile 500 kV transmission project.
Eldorado-Ivanpah: On July 1, 2013, SCE completed and energized the 35-mile doublecircuit,
230 kV transmission project.
Carrizo-Midway: On March 20, 2013, Pacific Gas and Electric (PG&E) completed and
energized the 35-mile double-circuit, 230 kV transmission project.
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2014 Projects
None.
2015 Projects
SCE/IID Joint Path 42: The SCE/IID Joint Path 42 project will increase the transfer capacity
from 600 MW to 1,500 MW of renewable energy from IID to SCE’s portion of the California
ISO controlled grid. SCE’s portion of the project includes upgrading a 15‐mile
double‐circuit, 230 kV transmission line between SCE’s Devers and Mirage Substations. The
IID upgrade consists of replacing 20 miles of a double‐circuit, 230 kV transmission line
between SCE’s Mirage and IID’s Coachella Valley and Ramon Substations. The project is
under construction.
Imperial Valley-Liebert: The Imperial Valley-Liebert project is a one‐mile 230 kV
transmission line from the new Liebert Substation to the existing Imperial Valley Substation.
The project will deliver at least 1,400 MW of renewable energy to the California ISO grid.
The project qualified for the California ISO’s competitive solicitation process. On July 11,
2013, the California ISO selected IID as the approved project sponsor. The project is under
construction.
El Centro-Imperial Valley: IID’s El Centro-Imperial Valley project, S line, replaces an
existing 230 kV line with a double-circuit 230 kV transmission line between the jointly
owned IID/SDG&E Imperial Valley Substation and the IID El Centro Switching Station. This
upgrade is required for completion of the Imperial Valley-Liebert project approved by the
California ISO. The project is under construction.
2016 Projects
Tehachapi Renewable Transmission Project: SCE’s Tehachapi Renewable Transmission
Project is being built in 11 segments and includes more than 300 miles of new and upgraded
220 kV and 500 kV transmission lines and substations. The project will deliver 4,500 MW of
renewable generation from eastern Kern and Los Angeles counties to the Los Angeles Basin.
Most of the generation will be wind resources from Kern County, but the line will also
accommodate future solar and geothermal projects. All segments except the underground
portion of Segment 8 are operational. The underground portion of Segment 8 is under
construction and expected to be in service in 2016.
Borden‐Gregg: PG&E will replace the existing Borden‐Gregg 230 kV transmission line with
a larger capacity conductor. The project will deliver 800 MW of solar generation proposed
near Fresno, specifically the Westlands area. The project was identified as needed in the
California ISO’s Generator Interconnection Procedures. The project is on hold until
generators make further progress, at which time PG&E will submit an application to the
CPUC requesting approval.
Barren Ridge Renewable Transmission Project: LADWP’s Barren Ridge Renewable
Transmission Project includes 87 miles of 230 kV transmission lines. The project will provide
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additional transmission capacity to access 1,400 MW of wind, solar, and other renewable
resources. The project is under construction.
2017 Projects
Sycamore‐Peñasquitos: The Sycamore‐Peñasquitos project is an 11-mile 230 kV
transmission line between SDG&E Sycamore and Peñasquitos Substations. The project will
deliver renewable generation and reliability benefits to the San Diego area. The project
qualified for the California ISO’s competitive solicitation process. On March 4, 2014, the
California ISO selected SDG&E and Citizens Energy Corporation as the approved project
sponsors. The project is in permitting at the CPUC.
South of Contra Costa: PG&E’s South of Contra Costa project includes replacing 47 miles of
existing 230 kV transmission lines south of the Contra Costa Substation with a larger
capacity conductor. The project will deliver 300 MW of wind generation in Solano County.
The project was identified as needed in the California ISO’s Generator Interconnection
Procedures. The project is on hold until generators make further progress, at which time
PG&E will apply to the CPUC requesting approval.
Warnerville‐Bellota: PG&E will replace the existing Warnerville‐Bellota 230 kV
transmission line with larger capacity conductor. The project, along with the Wilson‐Le
Grand and Gates‐Gregg projects discussed below, will deliver 700 MW of renewable
generation in the Greater Fresno, Central Valley North, Merced, and Westlands areas. The
project has an approved Notice of Exempt Construction and is in the engineering design
phase.
2018 Project
El Centro-to-Highline: IID’s El Centro-to-Highline project replaces existing 161 kV and 92
kV lines with a double-circuit 230 kV transmission line. IID identified the need for this
project to interconnect generation resources in its Transitional Cluster. The project is in the
engineering design phase.
2020 Projects
West of Devers: The West of Devers project consists of removing and replacing roughly 48
miles of existing 220 kV transmission lines with new double‐circuit, 220 kV transmission
lines between the existing SCE Devers Substation, Vista Substation, and San Bernardino
Substation. The project, combined with the Colorado River‐Valley project discussed earlier,
will deliver about 4,000 MW from Riverside County. The project is in the permitting stage.
Wilson‐Le Grand: PG&E will replace the existing Wilson‐Le Grand 115 kV transmission
line with larger capacity conductor. The project, along with the Warnerville‐Bellota project
discussed earlier and the Gates‐Gregg project discussed below, will deliver 700 MW of
renewable generation in the Greater Fresno, Central Valley North, Merced and Westlands
zones. The project has an approved Notice of Exempt Construction and is in the planning
phase.
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Delaney-Colorado River: The California ISO identified the need for an interregional 500 kV
transmission line between the existing SCE Colorado River Substation and the new APS
Delaney Substation as an economic project with reliability and policy benefits in its Board of
Governors-approved 2013-2014 Transmission Plan. The approximate length of the singlecircuit,
500 kV transmission line is 115-140 miles, depending on the approved route. The
project is eligible for competitive solicitation. On July 10, 2015, the California ISO selected
DCR Transmission, LLC, a joint venture company owned by Abengoa Transmission &
Infrastructure, LLC and an affiliate of Starwood Energy Group Global, Inc., as the approved
project sponsor to finance, construct, own, operate, and maintain the Delaney-Colorado
River project.
Harry Allen-Eldorado: The California ISO identified the need for an interregional 500 kV
transmission line between SCE majority-owned Eldorado Substation and NV Energy Harry
Allen Substation as an economic project with reliability and policy benefits in its Board of
Governors-approved 2013-2014 Transmission Plan. The approximate length of the singlecircuit,
500 kV transmission line is 60 miles. The project is eligible for competitive
solicitation.
2022 Projects
Gates‐Gregg (Central Valley Power Connect): The Gates‐Gregg project is a new
double‐circuit 230 kV transmission line between PG&E Gates and Gregg Substations. The
project, along with the Warnerville‐Bellota and Wilson‐Le Grand projects discussed earlier,
will allow for delivery of 700 MW of renewable generation in the Greater Fresno, Central
Valley North, Merced, and Westlands zones. The project qualified for the California ISO’s
competitive solicitation process. On November 7, 2013, the California ISO selected the
consortium of PG&E, MidAmerican Transmission, and Citizens Energy Corporation as the
approved project sponsors. The consortium recently renamed the project the Central Valley
Power Connect. 150 The project is in the engineering design phase and will file with the
CPUC in 2016.
Status of Removed Projects
Pisgah-Lugo: The California ISO identified the need for the Pisgah-Lugo transmission
project to interconnect the proposed Calico Solar Project. On June 20, 2013, K Road Calico
Solar, LLC filed a request with the Energy Commission to terminate the Calico Solar Project.
The Energy Commission approved this request on June 20, 2013. With the termination of the
Calico Solar Project, the California ISO determined that the Pisgah-Lugo transmission
project was no longer needed.
Coolwater-Lugo: The California ISO identified the need for the Coolwater-Lugo
transmission project to interconnect the Mojave Solar project with full capacity deliverability
150 http://cvpowerconnect.com/.
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status. In 2015, as a result of the California ISO’s annual reassessment of network upgrades
identified in previous generator interconnection studies, it determined the Coolwater-Lugo
transmission project was no longer needed to interconnect the Mojave Solar project with full
capacity deliverability status. The change in deliverability status for the Mojave Solar project
was primarily due to the election by several generating facilities in the area to permanently
retire and forego repowering. On April 20, 2015, the CPUC-assigned administrative law
judge (ALJ) issued a proposed decision 151 to dismiss without prejudice, or without any loss
of rights or privileges, SCE’s application for a certificate of public convenience and necessity
to construct the Coolwater-Lugo Transmission Project (A.13-08-023). On May 21, 2015, the
CPUC Commissioners approved the ALJ proposed decision. 152 SCE’s application was
closed.
Regional Transmission Planning
PacifiCorp Exploring Joining California ISO as Participating Transmission Owner
On April 13, 2015, the California ISO and PacifiCorp signed a memorandum of
understanding to explore the feasibility, costs and benefits of PacifiCorp’s full participation
in the California ISO as a participating transmission owner. As discussed above, PacifiCorp
participates in the California ISO’s 15-minute and 5-minute markets through the EIM.
Joining the California ISO would extend PacifiCorp’s participation to the day-ahead energy
market and allow for full coordination of the region’s two largest high-voltage transmission
grids in the West thereby giving customers served by both entities access to a broader array
of power generation at lower costs. A benefits study is underway and expected to be
completed by the end of fall 2015. If the results are favorable, PacifiCorp and the California
ISO would aim to reach a transition agreement in late 2015 to fully outline the steps and
timeline required for the transition. Necessary steps would include a full stakeholder
process to consider the tariff, policy, and process changes that need to be completed before
implementation. In addition, approval would be sought from the California ISO Board of
Governors, the public utility commissions in the six states where PacifiCorp serves
customers, and the FERC. 153 As noted in SB 350 (De León, 2015), Section 359 (a): It is the
intent of the Legislature to provide for the evolution of the Independent System Operator
into a regional organization to promote the development of regional electricity transmission
151 CPUC ALJ Moosen’s Proposed Decision can be found at
http://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M151/K169/151169662.PDF.
152 CPUC Commission Decision 15-05-040 can be found at
http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M152/K058/152058507.PDF.
153 California ISO-PacifiCorp FAQ: Expanding Regional Energy Partnerships, April 14, 2015,
http://www.caiso.com/Documents/FAQ-ExpandingRegionalEnergyPartnerships.pdf.
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markets in the western states and to improve the access of consumers served by the
Independent System Operator to those markets. 154
California ISO Regional Energy Market Proposal
On August 28, 2015, the California ISO announced that it is working to launch a regional
energy market to advance the state’s ambitious clean energy goals and to reduce the cost of
energy in the western states. Integrating clean, renewable energy on a coordinated western
grid more effectively uses resources and will reduce GHG emissions. This also allows for a
broader mix of renewables across the western region and provides tangible economic
benefits by allowing for the export of unusable renewable power, like solar, throughout the
region. Currently, oversupplies of solar energy generated in California cannot be
dispatched, but in a regional market, that oversupply could be sold cheaply to other states
to displace coal or natural gas generation in other service areas. 155
Western States Transmission Planning Trends
Interest in multistate transmission projects continues to increase in light of the 50 percent
RPS by 2030 requirement, the California ISO’s EIM covering eight states in the West
(discussed in Chapter 2), the potential addition of PacifiCorp to the California ISO’s
balancing authority area, and compliance with FERC’s interregional Order No. 1000.
Planned generation associated with several multistate transmission projects could provide
seasonal and geographical diversity that could complement California’s renewable
generation.
The Western states have continued to work closely together in the past two years through a
productive analytic period relying on the DOE funding for state planning. These states have
continued to monitor the evolution of reliability regulation in the western interconnection
through engagement with federal regulators (NERC and FERC) and the bifurcated regional
entities (WECC and Peak Reliability). The states’ interests have focused on implementing
the Energy Imbalance Market (addressed above) and transmission expansion planning.
Most recently, states have initiated important collaborative work related to carbon reduction
from electric generation, which will build on transmission expansion planning. This new
effort will require extensive coordination and complex analytics.
Ongoing Challenges: Engaging in Reliability Regulation
States have consistently emphasized the central importance of system reliability and have
been closely engaged in the evolution of regional reliability regulation. As described in the
154 See Senate Bill 350, Article 5.5. Transformation of the Independent System Operator, Section 359
(a), http://leginfo.legislature.ca.gov/faces/billNavClient.xhtml?bill_id=201520160SB350.
155 For more information on the proposal, see
http://www.caiso.com/informed/Pages/BenefitsofaRegionalEnergyMarket.aspx.
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2013 IEPR, one outcome of the September 8, 2011, Southwest outage was the restructuring of
WECC with the goal to separate the responsibility for real-time reliability operation from
the regulatory oversight functions of standards development and compliance enforcement.
On June 27, 2013, the WECC Board of Directors approved the bifurcation of the company
into a Regional Entity (WECC) and a Regional Coordination Company (Peak Reliability).
Thus, WECC retained its regulatory oversight functions, while Peak Reliability is
responsible for real-time reliability operation. The bylaws of each entity required an annual
governance review after one year of operation. These reviews identified a number of
successes as well as areas for continued refinement.
WECC succeeded in multiple areas, including unanimous approval of its budget and
business plans for 2015 and 2016, as well as renegotiation of its regional delegation
agreement, signed with NERC. In May 2015 WECC reached a settlement with FERC
regarding its responsibility (predating bifurcation) as the reliability coordinator at the time
of the Southwest outage. 156 As a result, FERC imposed significant monetary penalties on
WECC. On the other hand, members of some classes of WECC expressed complaints about
the cost of WECC, lack of access to decision-making, and opposition to use of Federal Power
Act Section 215 funding for non-traditional reliability matters.
Peak Reliability also succeeded in establishing itself as a new reliability coordinator.
However, there is debate over whether the appropriate funding mechanism is through
member contracts or Section 215. The Western Interconnection Regional Advisory Board
supported the Peak Reliability Board’s approach (contracting) after significant compromise
occurred. Controversy has also unfolded over how and who pays for what data transferred
from Peak Reliability to WECC.
Continuing Attention: Support for Western Transmission Expansion Planning
As described earlier in this chapter and noted in the August 3, 2015, IEPR workshop, a 50
percent RPS by 2030 requirement will entail development of renewable projects and
associated transmission additions. Key questions include what combination of technologies
present the best portfolio and how to value potential out-of-state resource and transmission
opportunities. These questions will be considered in two arenas: at the interconnectionwide
level with the WECC Transmission Expansion Planning Policy Committee (TEPPC) and at
the interregional level with the FERC Order 1000 planning regions. The RETI 2.0 effort could
also help inform future transmission planning efforts in the Western Interconnection.
With respect to interconnectionwide transmission planning, WECC and the states support a
robust transmission planning function, even though the DOE-funded American Recovery
156 Federal Energy Regulatory Commission, Order Approving Stipulation and Consent Agreement,
May 26, 2015, Docket No. IN14-11-000, http://www.ferc.gov/CalendarFiles/20150526093037-IN14-11-
000.pdf.
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and Reinvestment Act grants ended in 2014. TEPPC continues to lead a strong stakeholder
process that allows WECC to develop a production cost data-base that reflects consensus of
all major participants. The database includes assumptions necessary to perform production
cost assessments for varied generation and transmission futures. The assumptions are
reflected in the “common case,” which is used by multiple major utility, state and consultant
studies to address issues such as renewables integration. Among many other initiatives,
TEPPC’s Scenario Planning Steering Group has initiated a new major effort to develop a
climate change scenario and evaluate potential impacts of a 3 degree Fahrenheit increase in
temperature on the electric system in 2034. 157
The Western planning regions have made significant progress on interregional transmission
planning under FERC Order 1000. On May 10, 2013, the California ISO, Columbia Grid,
Northern Tier Transmission Group, and WestConnect filed tariff revisions to comply with
the interregional transmission coordination and cost allocation requirements of FERC Order
No. 1000. On December 18, 2014, FERC issued an order conditionally accepting their
interregional compliance filings subject to further filings. 158 On June 1, 2015, FERC issued a
final order accepting the California ISO, Northern Tier Transmission Group, and
WestConnect compliance filings with an effective date of October 1, 2015, and Columbia
Grid with an effective date of January 1, 2015. Beginning in 2016, as part of the California
ISO’s transmission planning process, proponents’ interregional transmission projects will be
evaluated over a two-year cycle. As the four Western planning region transmission plans
emerge over 2015-2016, WECC has committed to evolve its interconnection-wide approach
to best support and complement the regional tariff provisions and planning processes.
Pursuing New Initiatives: State and Regional Collaboration on Carbon Reduction
The Clean Power Plan, as described in Chapter 6, implements Section 111(d) of the 1990
Clean Air Act and is intended to reduce CO2 emissions from the electric sector by 32 percent
from 2005 levels by 2030. Western states had commented on the draft rule and had
organized themselves to collaborate in evaluating potential compliance paths that could be
considered. This was done in close coordination with WECC and the TEPPC analysis/staff
capabilities. Under the direction of the Western states 111(d) modeling task force, formed by
the Western Interstate Energy Board, WECC will conduct a test that will model two
hypothetical compliance scenarios provided by the states. This will include not only
evaluation of carbon reductions through production cost modeling, but evaluation of
potential reliability impacts of compliance. The latter assessment will rely on the WECC’s
157 WECC Scenario Planning Steering Group. Energy-Water-Climate Change Scenario Report. May 5,
2015. https://www.wecc.biz/_layouts/15/WopiFrame.aspx?sourcedoc=/Reliability/WECC-Energy-
Water-Climate-Change-Scenario-Final.pdf&action=default&DefaultItemOpen=1.
158 Interregional FERC Order No. 1000,
http://www.caiso.com/Documents/Dec18_2014_OrderConditionallyAcceptingOrder1000Interregional
Compliance_ER13-1470.pdf.
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emerging ability to perform an analysis that applies both production cost and power flow
modeling methods in sequence, relying on the Common Case as the starting point.
Multi-state Transmission Project Proposals
Centennial West Clean Line Transmission Project
The Centennial West Clean Line Transmission Project is an estimated 900-mile, 600 kV highvoltage
direct current (HVDC) line with a capacity of 3,500 MW that will connect wind and
solar resources in New Mexico and Arizona directly to the Southern California grid. 159 In
January 2011, Clean Line applied for a right-of-way across federal lands and submitted a
preliminary Plan of Development to the U.S. Bureau of Land Management (BLM). On June
18, 2012, the Centennial West Clean Line LLC and Western entered into an advance funding
agreement that outlines a working relationship to advance development of the proposed
Centennial West Clean Line Transmission Project. The projected in-service date is 2020.
Southwest Intertie Project
The Southwest Intertie Project (SWIP) is being developed by Great Basin Transmission, LLC
(an affiliate of LS Power) in three segments: Southwest Intertie Project – North, One Nevada
Transmission Line, and the Southern Nevada Intertie Project. The SWIP will provide access
to transmission for renewable generation and improve capacity and reliability for the
western grid. Once all three phases are completed, the project will provide 2,000 MW of
capacity and connect the existing high-voltage transmission infrastructure near Twin Falls,
Idaho, with existing systems in northern Nevada and the Las Vegas area.
The Southwest Intertie Project – North (SWIP North) is at the northern end of the SWIP
corridor and is a 275-mile, 500 kV transmission line from Idaho Power Midpoint Substation
to NV Energy Robinson Summit Substation. LS Power submitted an economic study request
for the SWIP North in the California ISO’s 2015-2016 transmission planning process that is
underway.
One Nevada Transmission Line is a 235-mile, 500 kV line from NV Energy Harry Allen
Substation to NV Energy Robinson Summit Substation and is the middle segment of the
SWIP. On January 23, 2014, the line was completed and energized, providing an initial
capacity of about 800 MW.
The Southern Nevada Intertie Project is an estimated 60-mile, 500 kV transmission line from
NV Energy Harry Allen Substation to SCE majority-owned Eldorado Substation. In the
California ISO’s 2013-2014 transmission planning process, the Harry Allen Substation to
Eldorado Substation was approved as an economic project with reliability and policy
benefits. The projected in-service date is 2020.
159 http://www.centennialwestcleanline.com/site/home.
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SunZia
The SunZia Southwest Transmission Project (SunZia) is sponsored by the Salt River Project,
Shell Wind Energy, Southwestern Power Group, Tri-State Generation and Transmission
Association, and Tucson Electric Power. SunZia is about 500-miles long and consists of two
single-circuit 500 kV transmission lines with 3,000 MW of capacity. The transmission lines
will originate from the proposed SunZia East Substation in Lincoln County, New Mexico,
and terminate at the TEP Pinal Central Substation in Pinal County, Arizona. SunZia
provides a point of interconnection for generating resources, including renewables, located
in Arizona and New Mexico for delivery to customers in the western markets. 160 On June 13,
2013, BLM published the Final Environmental Impact Statement (EIS) and Proposed
Resource Management Plan. 161 On January 24, 2015, the BLM issued a Record of Decision
approving SunZia’s application for a right of way across federally owned property. 162
Construction is slated to begin in 2018, with a projected in-service date of 2021.
TransWest Express Transmission Project
TransWest Express, LLC is developing the TransWest Express Transmission Project (TWE)
that is a 730-mile, 600 kV HVDC multistate transmission line with 3,000 MW of capacity.
TWE will deliver renewable energy produced in Wyoming to Arizona, Nevada, and
Southern California and provide a transmission backbone between the Intermountain and
Desert Southwest regions. TWE will run from south-central Wyoming, crossing Colorado
and Utah, to the LADWP Marketplace Substation about 25 miles south of Las Vegas,
Nevada. The Marketplace Substation provides interconnections to the California, Nevada,
and Arizona grids. About 67 percent of the preferred alternative route lies on federal land
principally managed by the BLM. The TWE follows designated utility corridors and is colocated
with existing transmission when possible to minimize impacts. On June 28, 2013, the
U.S. Environmental Protection Agency published in the Federal Register a Notice of
Availability for the BLM/Western Area Power Administration’s (Western’s) TransWest
Express Draft EIS with a comment period ending on September 25, 2013. 163 On April 30,
160 http://www.sunzia.net/index.php.
161 The Final EIS/RMPA can be found at
http://www.blm.gov/nm/st/en/prog/more/lands_realty/sunzia_southwest_transmission/feis/feis_docs
.html.
162 BLM Record of Decision can be found at
http://www.blm.gov/style/medialib/blm/nm/programs/more/lands_and_realty/sunzia/sunzia_docs.P
ar.94853.File.dat/SunZia_ROD_Record%20of%20Decision%20%281%29.pdf.
163 The Notice of Availability can be found in Federal Register/Volume 78, No.125/Friday, June 28,
2013/Notices, p. 38975, at http://www.gpo.gov/fdsys/pkg/FR-2013-06-28/pdf/2013-15612.pdf. The
Draft EIS can be found at
http://www.blm.gov/wy/st/en/info/NEPA/documents/hdd/transwest/DEIS.html#vol1.
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2015, BLM and Western published the Final EIS document. 164 On May 1, 2015, the U.S.
Department of Interior and U.S. Department of Energy published in the Federal Register a
Notice of Availability of the Final EIS. 165 The project proponent plans to begin construction
in 2017, with a projected in-service date of 2019.
Zephyr Power Transmission Project
In 2011, Duke-American Transmission Company (DATC) acquired the Zephyr Power
Transmission Project from TransCanada Corporation of Calgary. On September 23, 2014,
four companies—DATC, Pathfinder Renewable Wind Energy, Magnum Energy, and
Dresser-Rand—jointly proposed an $8 billion green energy initiative that will bring clean
electricity to the Los Angeles area by 2023. The project will require construction of the
proposed 2.1 gigawatt (GW) Pathfinder wind project in Wyoming, a 1.2 GW compressed-air
storage facility in Utah, and the corresponding 500 kV HVDC transmission line, about 525
miles long, with a capacity of 3,000 MW. A separate, existing 490-mile transmission line
traversing Utah, Nevada, and California would transport electricity from the Utah energy
storage facility to the Los Angeles area. The transmission line will maximize the use of
existing utility and federal energy corridors. 166
Opportunities for Facilitating Future Potential Transmission
Build-outs
Update on Right-Sizing Policy
Transmission right-sizing was first discussed in the 2011 IEPR and raised by stakeholders in
the 2014 IEPR Update. 167 Right-sizing entails looking beyond the current planning horizon—
typically 10 years—to see if needed projects should initially be built larger or built in such a
way that they can easily be made larger in the future. Where appropriate, right-sized
projects can reduce future costs and environmental impacts of transmission facilities. The
right-sizing concept was used throughout the Tehachapi Regional Transmission Project 168
164 The TWE Final EIS can be found at
http://www.blm.gov/wy/st/en/info/NEPA/documents/hdd/transwest/FEIS.html.
165 The Notice of Availability can be found in Federal Register/Volume 80, No.84/Friday, May 1,
2015/Notices, p. 24962, at
http://www.blm.gov/style/medialib/blm/wy/information/NEPA/hddo/twe/FEIS/8.Par.99152.File.dat/f
edregnotice-050115.pdf.
166 http://www.datcllc.com/projects/zephyr/.
167 California Energy Commission. 2015. 2014 Integrated Energy Policy Report Update. Publication
Number: CEC-100-2014-001-CMF. http://www.energy.ca.gov/2014publications/CEC-100-2014-
001/CEC-100-2014-001-CMF-small.pdf, pp. 153-154.
168 More information on the Tehachapi Renewable Transmission Project is available at
http://www.sce.com/tehachapi.
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where SCE built transmission facilities to 500 kV specifications but only energized the lines
at 220 kV.
In 2014, DATC submitted the San Luis Transmission Project in the California ISO’s 2014
request window. The San Luis Transmission Project is an example of a right-sizing
opportunity for the California ISO to evaluate, consistent with its tariff. In this case, Western
needs 230 kV facilities to provide power to the U.S. Bureau of Reclamation for the water
pumps at the San Luis Reservoir. The right-sizing opportunity would have DATC and
Western build the facilities to 500 kV specifications, with the California ISO funding 75
percent of the total cost, 169 in exchange for 1,200 MW of additional transmission capacity. In
its 2014-2015 Transmission Plan 170 the California ISO did not find an immediate need to
pursue this right-sizing project but acknowledged that it will continue to evaluate the
proposal in the 2015-2016 transmission planning process. While not every transmission
project is appropriate for right-sizing, California utilities and the California ISO should
continue looking beyond 10-year planning horizons and their own footprints for costeffective,
environmentally sound right-sizing opportunities.
Right-sizing could include:
• Planning/building a transmission project with a higher rating than is identified as
needed in the most current transmission plan because it is likely that more transmission
capacity will be needed beyond the current planning horizon.
• Building facilities to a higher capacity standard than is identified as needed but energize
them at the voltage needed today (that is, a 230 kV need built within a 500 kV right-ofway
with 500 kV towers). This leaves the option of increasing the capacity at a future
date with minimal environmental impact.
• Building joint projects to accommodate the needs of two or more transmission owners.
• Any combination of the above.
Many parties that commented on right-sizing at the August 3, 2015, IEPR workshop and/or
in written comments (Agricultural Energy Consumers Association, Defenders of Wildlife
and Sierra Club, Duke American Transmission Company, Natural Resources Defense
Council, TransCanyon LLC, and Westlands Solar Park LLC) agree that right-sizing is an
appropriate planning tool. For example, DATC provided detailed responses to staff’s rightsizing
questions that highlight California’s need for a comprehensive policy on transmission
right-sizing.
169 California ISO ratepayers would therefore be responsible for 75 percent of the total cost.
170 The California ISO 2014-2015 Transmission Plan is available at
http://www.caiso.com/Pages/documentsbygroup.aspx?GroupID=55EBA03B-525E-438B-8D9A-
C3C5B7B3DD3C.
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Given the limited availability corridors for new transmission lines, and the expectation that
corridors will be even more limited in the future, the state should assume right-sizing new
transmission facilities is the best option. California’s GHG policies will likely require
significant development of central station renewable generation that is not located near load
centers and will require new transmission lines. The corridors required for new
transmission facilities in California are limited by urban growth, terrain, and the need to
protect the environment. “As a practical matter, this means that any proposal to not rightsize
a transmission project should only be adopted after a careful examination of the longterm
environmental and economic consequences of such a decision.” 171 The state should
seek to maximize the value of the remaining corridors through right-sizing.
A comprehensive discussion of right-sizing and how it should be applied in California is
still required. The Energy Commission recommends that the state develop a set of rightsizing
policies through the 2016 IEPR Update process, informed by the RETI 2.0 process.
These policies, at a minimum, should include a comprehensive definition of right-sizing, as
well as describe the process through which the costs and benefits would be analyzed.
Transmission Corridors for Possible Designation
In 2004, Senate Bill 1565 (Bowen, Chapter 692, Statutes of 2004) directed the Energy
Commission, in consultation with other stakeholders, to adopt a strategic plan for the state’s
electric transmission grid. Subsequently, Senate Bill 1059 (Escutia and Morrow, Chapter 638,
Statutes of 2006) linked transmission planning and permitting by authorizing the Energy
Commission to designate transmission corridor zones on nonfederal lands to allow for the
timely permitting of future high-voltage transmission projects, with the further requirement
that any corridor proposed for designation must be consistent with the state's needs and
objectives as identified in the latest adopted strategic transmission investment plan.
The 2013 IEPR, which includes the 2013 Strategic Transmission Investment Plan, makes the
following recommendation with respect to corridors that would be appropriate for
designation: “From a timing perspective, it makes sense to identify and designate, where
appropriate, transmission corridors in advance of future generation development so that
needed transmission projects can be permitted and built in an effective, environmentally
responsible manner, contemporaneous with the generation development. The Energy
Commission will work with the utilities; federal, state, and local agencies; and stakeholders
to identify transmission line corridors that are a high priority for designation such as those
corridors that would ease the development of renewable energy resources. Appropriate
171 Christopher Ellison, Ellison, Schneider & Harris LLP. Duke American Transmission Company’s
Comments on the 2015 Integrated Energy Policy Report: Transmission and Landscape-Scale Planning. Docket
15-IEPR-08. August 17, 2015. http://docketpublic.energy.ca.gov/PublicDocuments/15-IEPR-
08/TN205763_20150817T155259_Christopher_T_Ellison_Comments_Duke_America_Transmission_C
ompan.pdf, p. 5.
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corridors could be identified as a result of the Desert Renewable Energy Conservation Plan
effort, future examination of opportunities and needs in the San Joaquin Valley (southern
area of the Central Valley), and the ongoing San Onofre transmission alternatives under
consideration.”
The 2014 IEPR Update discussed the Energy Commission-funded consultant report (and
subsequent addenda) that provides a high‐level assessment of the environmental feasibility
of several electric transmission alternatives under consideration by the California ISO to
address reliability and other system challenges resulting from the San Onofre closure. The
2014 IEPR Update noted that one or more of the alternatives may be considered by Energy
Commission staff in the state’s electric transmission corridor designation process.
The Energy Commission staff summarized this recent history of corridor identification at
the August 3, 2015, IEPR workshop and solicited feedback from stakeholders on the
appropriate corridor opportunities to be identified for the 2015 IEPR. 172 Westlands Solar
Park submitted written comments, in which they agree with the 2013 IEPR recommendation
that the San Joaquin Valley is an important area for corridor consideration. They
recommend that the Energy Commission explore ways to use its transmission corridor
planning and designation authority under Senate Bill 1059 to coordinate and partner with
local and federal agencies, especially in regions such as the San Joaquin Valley where
multiple transmission projects (the Gates-Gregg Central Valley Power Connect and the San
Luis Transmission Project) are proposed. Westlands Solar Park recommends that the Energy
Commission work with the CPUC, California ISO, Western Area Power Administration
Sierra Nevada region office, and local governments to develop a transmission planning
strategy that best adheres to the Garamendi Principles and that right-sizes the proposed
transmission improvements, thereby minimizing the need to create new corridors. No
parties proposed any additions or deletions to the 2013 IEPR recommendation on highpriority
corridors. However, parties believe RETI 2.0 provides an opportunity for the
identification of high-priority corridors to expedite long-term transmission planning goals.
As mentioned above, this effort should also include continuity with federal Section 368
corridors.
Update on Deliverability Issue Identified in the 2013 IEPR
The 2013 IEPR also discusses recent efforts to improve the coordination between generation
and transmission planning and permitting. Improvement in better synchronizing generation
development and the transmission upgrades is needed to reliably interconnect and deliver
172 Judy Grau (Energy Commission), Strategic Transmission Planning and Corridors presentation,
presented at the IEPR Workshop on Landscape-Scale Environmental Evaluations for Energy
Infrastructure Planning and the Strategic Transmission Investment Plan, August 3, 2015, slides 5 and
8, http://docketpublic.energy.ca.gov/PublicDocuments/15-IEPR-
08/TN205566_20150730T112902_Strategic_Transmission_Planning_and_Corridors.ppt.
115

that generation to load. The 2013 IEPR noted that the power purchase agreements signed by
renewable generators typically require full deliverability during peak conditions, which can
require costly transmission upgrades that may not be operational until several years after
the generator is on-line. To that end, the Energy Commission made the following
recommendation: “The cost-effectiveness, prudency, and alternatives for requiring full
deliverability for future renewable generation that is procured to meet RPS requirements
should be evaluated by California’s energy agencies in the overall context of long-term
planning for meeting RPS and GHG emission reduction goals.”
In response to this recommendation, the California energy agencies began evaluating full
deliverability requirements for renewable generators required to meet future RPS and GHG
reduction goals. The CPUC Order Instituting Rulemaking to Continue Implementation and
Administration, and Consider Further Development of, California Renewables Portfolio Standard
Program 173 discusses deliverability requirements as part of the instructions for the
development of 2015 Renewables Portfolio Standard Procurement Plans and in the ongoing
process to revise the RPS Calculator. The California ISO in its 2015-2016 transmission
planning process will perform a sensitivity study that analyzes the impacts of energy-only
renewables (resources that are not fully deliverable) in 2030. These steps effectively fold the
analysis of deliverability requirements for renewables into existing planning and
procurement processes.
The CPUC requires utilities to discuss needs for renewable resources with various
characteristics in their plans to meet RPS program requirements. The Assigned
Commissioner’s Revised Ruling Identifying Issues and Schedule of Review for 2015 Renewables
Portfolio Standard Procurement Plans requires the utilities to include within their RPS plans a
description of the specific characteristics of the renewable resources they are seeking. As
noted in the ruling, “This written description must include the retail seller’s need for RPS
resources with specific deliverability characteristics, such as peaking, dispatchable,
baseload, firm, and as-available capacity as well as any additional factors, such as ability
and/or willingness to be curtailed, operational flexibility, etc.” 174 Utility procurement plans
are also required to evaluate resources using a least-cost, best-fit method that includes
transmission congestion and capacity valuations.
173 Order Instituting Rulemaking to Continue Implementation and Administration, and Consider Further
Development, of California Renewables Portfolio Standard Program, March 6, 2015,
http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M148/K296/148296751.PDF.
174 Assigned Commissioner’s Revised Ruling Identifying Issues and Schedule of Review for 2015 Renewables
Portfolio Standard Procurement Plans, p. 9, May 28, 2015,
http://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M152/K045/152045579.PDF.
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The CPUC is also considering deliverability requirements for renewable generators in its
update of the RPS Calculator. The CPUC staff’s Draft 2015-2016 RPS Calculator Work Plan 175
includes modifications that would allow and account for energy-only renewable projects.
Coordinating with the CPUC staff, the California ISO is studying ways to analyze energyonly
resources and incorporate them into the RPS Calculator. The California ISO’s special
study will be incorporated into the 2015-2016 transmission planning process.
As renewable generation requirements grow, California energy agencies are exploring the
value of energy-only renewable resources. Full deliverability is no longer a presumed
requirement for renewable resources in utility portfolios. The California energy agencies are
making great progress on the issue of deliverability for renewable resources, and efforts
should be continued in both the CPUC procurement process and California ISO
transmission planning.
Recommendations
• Explore extending local government planning grants to additional, resource rich
areas. The Energy Commission should explore opportunities to extend renewable
energy planning grants to local governments in areas of the state where significant
amounts of renewable development are anticipated.
• Develop informational materials to support local government public outreach. The
Energy Commission should develop informational fact sheets and other educational
materials about renewable energy projects to support local government and public
outreach. These resources should be made available on the Commission’s website.
• Leverage analytical tools to conduct further landscape-scale analysis for
renewable planning. The Energy Commission should continue to leverage the tools
and approaches developed for the Desert Renewable Energy Conservation Plan and
related planning efforts to ease successful landscape-scale planning of renewable
resources, transmission investments, and conservation.
• Encourage county planning efforts and use best practices in RETI 2.0. The Energy
Commission should assist and encourage county planning efforts that support state
climate, renewable energy, conservation and climate adaptation policy goals. The
Energy Commission should work closely with stakeholders to ensure the RETI 2.0
planning process is open, transparent, and science-based and provides for robust
stakeholder dialogue and engagement.
175 Administrative Law Judge’s Ruling Seeking Post-Workshop Comments, Attachment A: Energy Division
Staff’s Draft 2015-2016 RPS Calculator Work Plan, April 13, 2015,
http://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M151/K169/151169497.PDF.
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• To support the 50 percent RPS by 2030 goal and the development of a regional
electricity market in the West, encourage the transformation of the California ISO
into a regional organization. To promote the development of regional electricity
transmission markets in the Western states and to improve the access of consumers
served by the California ISO to those markets, the state should encourage PacifiCorp
and other entities to join the California ISO as a participating transmission owner,
allowing for further coordination of high-voltage transmission grids in the West.
• Develop right-sizing policies. The Energy Commission recommends that the state
develop a set of right-sizing policies through the 2016 Integrated Energy Policy Report
Update process and informed by RETI 2.0. These policies, at a minimum, should
include a comprehensive definition of right-sizing, as well as describe the process
through which the costs and benefits would be analyzed.
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CHAPTER 4:
Transportation
California has long been a leader in achieving needed reductions from the transportation
sector to meet climate and clean air goals and today’s transportation sector is cleaner and
more efficient than it was even several years ago. However, there is still more to be done.
The production, refining and use of petroleum represent some of the state’s largest sources
of pollution—accounting for about 40 percent of California’s greenhouse gas (GHG)
emissions, 80 percent of smog-forming emissions, and over 95 percent of diesel particulate
matter emissions. To help address these environmental quality issues, the state has
developed a portfolio of rules, regulations, goals, policies, and strategies designed to
address emission reductions, air quality, and petroleum reductions while meeting
transportation demands of the future.
This chapter starts with a discussion of many of these regulations and goals. The chapter
then highlights the Governor’s 2030 climate goals and summarizes the state’s framework for
decarbonizing the transportation sector. It also provides the Energy Commission’s
preliminary transportation energy demand forecast through 2026, an analysis of
transportation fuel trends, and concludes with a discussion of the benefits of the Energy
Commission’s Alternative and Renewable Fuel and Vehicle Technology Program
(ARFVTP)—a critical part of the state strategy to deploy alternative fuels and advanced
vehicle technologies into California’s transportation market.
Achieving Greenhouse Gas Reduction and Clean Air Goals
The Federal Clean Air Act requires the U.S. Environmental Protection Agency (U.S. EPA) to
set outdoor air quality standards for the nation. It also allows states to adopt more
protective air quality standards if needed. Through the State Implementation Process,
California identifies the strategies needed across sectors to achieve state and federal air
quality standards. In addition to the state’s ambitious air quality goals, California also has
progressive goals for combating climate change. California’s goals for GHG emission
reductions originated with the goal of reducing GHG emissions to 1990 levels by 2020
established by Assembly Bill 32 (Núñez, Chapter 488, Statutes of 2006) (AB 32). Governor
Brown built upon this goal in issuing an Executive Order for California to reduce GHG
emissions to 40 percent below 1990 levels by 2030 in his April 2015 Executive Order B-30-
15. 176
176 Governor Edmund G. Brown Jr., Executive Order B-30-15, April 29, 2015,
http://gov.ca.gov/news.php?id=18938
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California already has an effective suite of policies, plans, and programs aimed at reducing
air pollution and GHG emissions from the transportation system. These policies range from
increasingly stringent tailpipe emission standards for cars and trucks, regulations requiring
the development and sale of zero-emission technology vehicles, incentive programs for
zero-emission vehicles (ZEV) and near-ZEV technology development, and strategies for
integrated land use development to reduce vehicle travel demand. As a result of these goals
and policies, the state has implemented a number of programs and plans to put California
on a path of transitioning to a diversified alternative and low-carbon fueled transportation
future.
While the state is on track to meet its 2020 climate change target set by Assembly Bill 32,
more is needed to achieve its air quality and long-term climate goals. Recognizing this,
Governor Edmund G. Brown Jr. has issued Executive Orders and provided strong
leadership and direction, including:
• Issuing in March 2012 an Executive Order calling for 1.5 million zero-emission
vehicles to be on California roadways by 2025, and adequate infrastructure to
support one million zero-emission vehicles by 2020. 177 To chart a path toward
meeting the Governor’s ZEV Executive Order, the 2013 ZEV Action Plan 178 delineates
specific actions for California agencies to facilitate deployment and adoption of ZEVrelated
fueling and charging infrastructure. The 2013 ZEV Action Plan is currently
being updated.
• Calling for a 50 percent reduction in petroleum used by California’s cars and trucks
by 2030 in his 2015 inaugural address. 179
• Setting a goal for California to reduce its GHG emissions 40 percent below 1990
levels by 2030.
• Directing state agencies to work together to develop an integrated action plan that
establishes targets to improve freight efficiency, increases adoption of zero-emission
technologies, and increases competitiveness of California’s freight system in his July
2015 Executive Order B-32-15. 180
177 Governor Edmund G. Brown Jr., Executive Order B-16-12, March 23, 2012,
http://gov.ca.gov/news.php?id=17463.
178 Office of Governor Edmund G. Brown Jr., 2013 ZEV Action Plan, February 2013,
http://opr.ca.gov/docs/Governor's_Office_ZEV_Action_Plan_(02-13).pdf.
179 Governor Edmund G. Brown Jr., Inaugural Address, January 5, 2015,
http://gov.ca.gov/news.php?id=18828.
180 Governor Edmund G. Brown Jr., Executive Order B-32-15, July 17, 2015,
http://gov.ca.gov/news.php?id=19046.
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Clean Vehicle and Fuel Programs
Below is lists some of the programs in place to help advance low-carbon, clean fuels in
California.
• Advanced Clean Cars: The California Air Resources Board’s (ARB’s) Advanced
Clean Cars regulatory program integrates regulatory standards for GHG emissions
and criteria air pollution emissions for California’s passenger vehicles. As part of this
program, ARB adopted a ZEV regulation that requires 1.4 million zero-and near-zero
emission vehicles be on the road by 2025. ZEVs such as battery electric and hydrogen
fuel cell electric are expected to account for 15 percent of all new car sales by 2025.
• State Implementation Plan: To meet federal health-based air quality standards, air
basins in extreme nonattainment with ozone standards, such as the San Joaquin
Valley and South Coast air basins, could require up to an 80 percent reduction in
transportation oxides of nitrogen (NOx) emissions from current regulatory levels
between 2023 and 2032. Air Districts are pursuing local strategies to reduce these
emissions.
• U.S. EPA “Phase 2 Program”: The U.S. EPA and Department of Transportation’s
National Highway Traffic Safety Administration (NHTSA) are jointly proposing a
national program that would establish standards to support the development and
deployment of cost-effective technologies that will help reduce GHG emissions and
promote energy security through vehicle efficiency gains.
• Low Carbon Fuel Standard (LCFS): The LCFS requires a 10 percent reduction in the
carbon intensity of all fuels sold in California by 2020. Importers and refiners of
petroleum fuels are required to reduce the carbon intensity of their fuels products by
developing their own low-carbon fuels, or by buying LCFS credits from third-party
developers of low-carbon fuels.
• Cap-and-Trade Program: Implemented as part of AB 32, the Cap-and-Trade
Program sets a cap on GHG emissions and requires covered industries to reduce
emissions or purchase permits accordingly. Starting January 1, 2015, fuels such as
gasoline, diesel and natural gas are included under the Cap-and-Trade Program.
This inclusion will require fuel suppliers to reduce the GHG emissions produced
when the fuel they sell is burned, either by lowering the carbon content of the fuel or
by purchasing pollution permits.
Transportation Demand Management Policies and Strategies
As part of its multipronged effort to advance its transportation sector goals, the state is also
implementing programs to help reduce transportation demand as listed below.
• Senate Bill 375: The Sustainable Communities and Climate Protection Act of 2008
(Sustainable Communities Act, Chapter 728, Statutes of 2008) (SB 375) requires
Metropolitan Planning Organizations to demonstrate how their regions will meet
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egional GHG reduction targets by reducing passenger vehicle travel demand
through more integrated land use, housing, and transportation planning.
• California Department of Transportation (CalTrans) Freight Mobility Plan:
Several elements of the Freight Mobility Plan will also help reduce transportation
vehicle miles traveled (VMT), including CalTrans’ efforts to reduce congestion and
introduce advanced efficiency technologies into traffic management systems.
• High-Speed Rail (HSR): California’s High-Speed Rail Authority will develop a
modern high-speed electric rail system between San Francisco and Los Angeles. HSR
is projected to reduce petroleum fuel consumption by 2 billion to 3 billion barrels per
year by 2030 and reduce VMT by 10 million miles per day by 2040.
Providing Incentives for the Transformation
The transition toward cleaner technologies, lower carbon fuels, and more sustainable
choices will also require marked public investment to spur technology and market
development and needed infrastructure. The state’s current transportation incentive
funding includes:
• AB 118 and AB 8: The Energy Commission and ARB incentive funding programs
authorized by AB 118, Núñez, Chapter 750, Statutes of 2007) and AB 8 (Perea,
Chapter 401, Statutes of 2013), respectively, will provide about $2 billion in incentive
funding between 2007 and 2024 for development and deployment of alternative
technology vehicles, fueling infrastructure, and fuels. The ARFVTP has invested
nearly $600 million in about 500 projects to develop and deploy ZEV and near-ZEV
fueling and charging infrastructure, sustainable low-carbon biofuels, and ZEV and
near-zero-emission vehicle technologies.
• Proposition 1B: Out of the nearly $740 million in Proposition 1B funding for
emission reductions through June 2015, more than $735 million has been used to
offer incentives for cleaner trucks, including early compliance with the 2010 clean
diesel truck regulatory standards. 181 By 2017, all California trucks will need to
comply with this standard. ARB is modifying the Proposition 1B fund program
regulations to allow for eligibility of alternative fueled trucks, such as natural gasfueled
trucks with low emissions of NOx.
• Cap-and-Trade Auction Proceeds: Each year, the Legislature and Governor
appropriate proceeds from the sale of state-owned allowances out of the Greenhouse
181 ARB, Proposition 1B: Goods Movement Emission Reduction Program – 2015 Funding Awards, Staff
Report, September 2015,
http://www.arb.ca.gov/bonds/gmbond/docs/prop_1b_goods_movement_program_september_2015_s
taff_report.pdf.
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Gas Reduction Fund (GGRF) for projects that support the goals of AB 32. The GGRF
is an important part of the state’s overall climate investment efforts. With this
money, the state is funding the accelerated adoption of ZEVs—including innovative
clean bus/truck technology demonstrations, public transit investment, affordable
transit-oriented housing, and sustainable community strategies for the most
disadvantaged communities.
The ongoing AB 8 investments for the ARB’s Air Quality Improvement Program (AQIP) and
Energy Commission’s ARFVTP, bolstered with funding from Cap-and-Trade auction
proceeds, are helping increase consumer acceptance and use next generation ZEVs.
Pending Actions
Building upon the success of California’s current array of programs and policies, several
efforts and activities are underway to accelerate transformation of the transportation sector
to attain the needed reductions in carbon, criteria, and particulate emissions.
• Utility Proposals for ZEV Infrastructure: California’s three large investor-owned
utilities have submitted applications to the California Public Utilities Commission to
allow for installation of up to 60,000 electric vehicle chargers throughout California.
If approved, these initiatives would substantially accelerate the deployment of
electric vehicle chargers in California beyond the current level of about 2,500
installed public chargers, in accordance with the Governor’s ZEV Mandate to
accommodate 1 million ZEVs by 2020. Senate Bill 350 (De León and Leno, 2015),
requires the CPUC, in consultation with the ARB and Energy Commission, to direct
electrical corporations to file applications for programs and investments to accelerate
transportation electrification, reducing California’s dependence on petroleum.
• California Sustainable Freight Strategy: Governor Brown’s Executive Order B-32-
15 182 requires the California State Transportation Agency, Environmental Protection
Agency, Natural Resources Agency, CalTrans, ARB, the Energy Commission, and
the Governor’s Office of Business and Economic Development to establish clear
targets for emissions reductions while maintaining the economic competitiveness of
California’s ports and freight sector by July 2016.
• 2030 Petroleum Reduction Effort: The ARB convened a symposium on July 8, 2015,
which hosted representatives from several state agencies and research organizations.
2030 Climate Commitments
As part of his 2015 inaugural address, Governor Brown outlined five pillars for meeting the
goal of 40 percent GHG emission reductions from 1990 levels by 2030. Within the
182 Governor Edmund G. Brown Jr., Executive Order B-32-15, July 17, 2015,
http://gov.ca.gov/news.php?id=19046.
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transportation sector, this included a goal of reducing today’s petroleum use in cars and
trucks by up to 50 percent. At its July 8, 2015, symposium, panelists discussed pathways for
reducing petroleum consumption within the framework of sustainable freight leadership,
advanced vehicle technologies, cleaner fuels, and smarter growth and transportation
choices. Below are highlights that came out of the symposium about what might be needed
to achieve the 2030 goal.
• Reducing petroleum use in California will require building on and accelerating
existing air quality and climate efforts, including:
o
o
o
o
Improving existing vehicle fuel efficiencies for both passenger vehicles and
light trucks (through the use of lightweight materials, variable speed
transmissions, efficient drive trains, and so forth). These efficiencies are
largely driven by federal fuel economy standards.
Continuing to accelerate the technology advancement and adoption of zeroemission
vehicles in both the light- and heavy-duty sectors.
Where zero emission technologies and fuels are not currently available, such
as in many heavy-duty applications, the replacement of diesel and gasoline
with alternative and renewable fuels can greatly reduce the carbon intensity
of these operations.
Reducing vehicle travel demand through better transportation and land use
planning being pursued through regional Sustainable Communities Strategy
development.
• New strategies will be explored through several new planning efforts, which
include:
o
o
o
Short-Lived Climate Pollutants Plan, being developed by the ARB. This plan
will identify strategies to reduce methane, black carbon, and fluorinated
gases.
Sustainable Freight Strategy, a multi-agency effort to build supply chain
efficiencies throughout California’s freight sector.
Update to the Scoping Plan, being developing by ARB in consultation with
other state agencies. This Plan will identify new strategies across economic
sectors, including natural and working lands, energy, and more, to address
the Governor’s 2030 climate reduction targets.
Achieving this ambitious climate goal will require a sustained and accelerated
transformation of California’s transportation system. The state strategy for decarbonizing its
vast transportation sector includes increasing the use of cleaner vehicles with zero-emission
and near-zero emission technologies in all vehicle categories; reducing the carbon content of
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motor vehicle, rail, and aviation fuels; reducing vehicle travel demand; and improving
system efficiencies.
Preliminary Transportation Energy Demand Forecast
The state and federal policies discussed above encourage the development and use of
renewable and alternative fuels and technologies to reduce California’s dependence on
petroleum-based fuels, cut GHG emissions, and promote sustainability. While there has
been significant growth in these fuels in recent years, the Energy Commission’s preliminary
transportation energy demand forecast shows that gasoline and diesel will continue to be
the primary sources of transportation fuel through 2026.
The increasing interrelationship and impact the transportation sector will have on electricity
and other energy sectors requires a strong ability to forecast transportation energy demand
to inform near- and mid-term electricity procurement, provide historically-based projections
to conservatively gauge progress, and to subsequently inform policy and program
adjustments/redirection.
Forecasting Models
The preliminary forecast presented here results from several inputs and assumptions run in
behavioral models that represent key transportation sectors in California. These behavioral
models represent light-duty vehicle demand for both residential and commercial sectors,
urban and intercity travel demand, and travel demand for freight transport and service
provisions. With the exception of aviation/jet fuel demand, there have been no major
changes to the preliminary transportation energy demand forecast process since 2013. For
the revised forecast to be completed later this year and incorporated in the final version of
the 2015 Integrated Energy Policy Report (IEPR), electricity demand for off-road applications,
such as electrification of California’s ports, will be included.
Unlike the transportation energy demand forecasts prepared in 2011 and 2013, the aviation
fuel demand forecast in the 2015 IEPR is not derived from behavioral models at the Energy
Commission due to resource and data constraints, and therefore does not respond to
variations in key inputs used for other transportation sector models presented here.
The transportation energy demand forecast shows the results for three demand cases, which
apply the same economic and demographic inputs and energy prices as the demand cases
used in the electricity and natural gas demand forecasts prepared by the Energy
Commission. The electricity and natural gas forecasts are discussed in Chapters 5 and 6,
respectively.
Demand Cases: Overview and Assumptions
The transportation energy demand case definitions are consistent with the “common
demand cases” referenced throughout the 2015 IEPR. The economic, demographic, and
price inputs for these cases are common to the various forecasting efforts at the Energy
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Commission, including electricity and natural gas. The three common demand cases are
defined as follows:
• High demand case: High population and income, and low energy prices.
• Reference demand case: Reference population, income, and energy prices.
• Low demand case: Low population and income, and high energy prices.
More details on these demand cases can be found in Chapter 5 on California’s electricity
demand forecast.
Two additional demand cases will be developed in the revised transportation energy
demand forecast as follows:
• High petroleum demand case: High population, income, and compressed natural
gas and electricity prices, and low petroleum fuel prices.
• Low petroleum demand case: Low population, income, and compressed natural gas
and electricity prices, and high petroleum fuel prices.
Various local, state, and federal regulations; standards; and incentive programs apply to the
transportation sector, all of which aim to address climate change and improve air quality
and energy security. The primary regulations and incentives considered in this forecast
include the NHTSA CAFE standards for passenger car and light truck model years 2017–
2021, California’s LCFS, and California’s ZEV regulation, as these regulations can be
quantified. Proposed laws and regulations are not considered in this forecast because there
can be significant changes to those regulations prior to adoption.
Since both the ZEV mandate and Corporate Average Fuel Economy (CAFE) standards apply
to manufacturers, they are met by the attributes of vehicles (such as vehicle price and miles
per gallon) in the market. The current ZEV mandate and CAFE standards are captured in all
the transportation demand cases used in this forecast through the vehicle attribute
projections that are used.
The California High-Speed Rail Authority provided its high-speed rail electricity demand
forecast to the Energy Commission that is included in the reference demand case. Further
explanation as to how high-speed rail electricity demand is incorporated into this forecast is
discussed later in this chapter.
Finally, the Energy Commission’s behavioral demand models do not necessarily account for
all transportation regulations and goals. For example, the Sustainable Communities Act (SB
375), which requires the reduction of GHG emissions through coordinated transportation
and land-use planning, is not considered at this time. In addition, the Governor’s Executive
Order calling for a 50 percent reduction in petroleum consumption is not incorporated into
forecasting assumptions as the mechanisms to achieve this goal are still being determined.
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Sectors
Transportation energy is used for moving people and freight for personal and commercial
purposes, in light-duty, medium-duty, and heavy-duty vehicles using multiple travel
modes on the ground and in the air. Light-duty vehicles (LDVs) serve the personal
transportation needs of the residential and commercial sectors, as well as the overall needs
of the rental and government sectors. LDVs compete with bus and rail in urban (local)
travel, and with bus, rail, and airplanes in intercity (long-distance) travel. Medium-duty
vehicles (MDVs) and heavy-duty vehicles (HDVs) are used in mass transit of people and
services, and in freight transport, where they compete with rail and air freight. HDVs also
provide services for local activities such as construction and refuse movements, in the
absence of competition from other modes. Transportation energy demand covers all these
movements in all sectors, accounting for vehicle populations and fuel economies, as well as
VMT.
Key Inputs
The models and surveys conducted by the Energy Commission’s Demand Analysis Office
show that the key drivers of transportation fuel and vehicle demand are population,
economy, and fuel and vehicle prices. Transportation fuel prices are crucial to the
transportation energy demand forecast, as consumers are sensitive to the current price of
fuel when deciding on which type of vehicle to purchase.
Transportation Energy Price Forecast
According to the U.S. Energy Information Administration (EIA), prices for petroleum fuel
have seen a significant shakeup since 2013, driven by a precipitous drop in crude prices, as
shown in Figure 18. For further discussion on crude oil prices and national and global
trends in production, see Changing Trends in California’s Sources of Crude Oil in Chapter 7.
Figure 18: West Texas Intermediate Crude Oil Monthly Spot Prices
Source: Energy Information Administration
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The Energy Commission traditionally looks to the Annual Energy Outlook (AEO), published
by the EIA, for crude oil price forecasts to serve as inputs to the transportation liquid fuel
price forecasts.
The Crude Oil Refiner Acquisition Cost (RAC) is the cost of crude oil, including
transportation and other fees paid by the refiner. Staff used EIA’s forecast of RAC prices for
the Petroleum Administration for Defense District (PADD) for the west coast (Alaska,
Arizona, California, Hawaii, Nevada, Oregon, and Washington), known as PADD 5.
Composite PADD RAC prices include both domestic and imported crude oil. The
preliminary Energy Commission RAC forecast was constructed by assembling parts of the
February 2015 Short Term Energy Outlook, also published by EIA, and the 2014 AEO
scenarios.
The crude oil prices in Figure 19 were used to forecast preliminary liquid fuel prices.
Figure 19: Preliminary Crude Oil Cost (Refiner Acquisition Cost) Forecast, (2012$)
Source: Energy Commission, Supply Analysis Office and Energy Information Administration
The natural gas, electricity, and hydrogen prices, which were developed based on the
Energy Commission’s Supply Analysis Office’s price analysis for the 2013 Natural Gas
Outlook and California Energy Demand 2013-2024, Preliminary Electricity Forecast, were also
used in this forecast. Hydrogen prices were derived from natural gas as the source fuel in
steam reformation. However, the revised price forecast will include the revised 2015 natural
gas and electricity prices and will revise hydrogen price forecast to include scenarios that
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derive hydrogen prices from electricity prices, as well, which may alter cost per mile of
these fuels.
To derive fuel cost per mile, staff used fuel economies for compact cars from the EIA. 183
Once vehicle fuel economies are accounted for, electric vehicles have the lowest cost per
mile. An example for a compact vehicle is shown below in Figure 20.
Figure 20: Preliminary Forecast of Cost per Mile (Compact Vehicles)
Source: Energy Commission, Supply Analysis Office and Energy Information Administration
After the Energy Commission staff developed the preliminary transportation fuel price
forecast in April 2015, the EIA later published its 2015 AEO crude oil price forecast. The
revised transportation energy demand forecast will use the revised fuel price forecasts
derived from this recent AEO price forecast.
183 http://www.fueleconomy.gov/.
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Transportation Energy Demand Forecast
Different fuel types dominate different transportation sectors in California. While natural
gas dominates public transit, diesel is the dominant fuel in freight movement, and gasoline
dominates the LDV sector. However, data from recent years, along with the forecast show
that alternative fuels, such as electricity and E-85, are growing across sectors in California.
Alternative fuels as defined for this forecast include electricity, hydrogen, ethanol, and
natural gas.
Gasoline
Data from the Department of Motor Vehicles show that gasoline demand is largely driven
by LDVs, which represent more than 90 percent of all gasoline consumption in California.
As shown in Figure 21, gasoline vehicles made up 92 percent of California LDVs in 2013.
Gasoline also fuels hybrid vehicles and accounts for more than 95 percent of the fuel used
by flexible-fuel vehicles in California. In other words, 95 percent of the time, flexible-fuel
vehicle owners use gasoline instead of E-85 when refueling.
Figure 21: California Light-Duty Vehicle Distribution by Fuel Type
Source: Energy Commission and Department of Motor Vehicles
CAFE standards provide for significantly improved fuel economy, and NHTSA estimates
that this trend will continue through 2025. Figure 22 shows NHTSA’s estimates of
cumulative fuel savings as these standards are applied over time.
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Figure 22: NHTSA’s Estimates of CAFE’s Cumulative Fuel Savings for the U.S. Fleet
Source: U.S. Department of Transportation 184
Figure 23 shows the preliminary gasoline demand forecast for all transportation sectors,
travel modes, and both LDV and HDV classes on-road in California. Most of the demand for
gasoline in California can be attributed to LDVs in the residential sector. The slow growth in
population, coupled with improvements in fuel economy explains the overall decline in
demand for gasoline.
All three demand forecast cases show reductions of up to 2 percent per year due to
improved fuel economy, driven by CAFE standards and displacement by alternative fuels,
primarily driven by the ZEV regulations.
184 http://www.transportation.gov/mission/sustainability/corporate-average-fuel-economy-cafestandards.
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Figure 23: Preliminary California On-Road Gasoline Demand Forecast
Source: California Energy Commission
The preliminary gasoline demand forecast will be revised, based on revised transportation
energy price forecasts and revised vehicle attribute projections.
Diesel
In contrast to gasoline, most on-road diesel is consumed by medium- and heavy-duty
vehicles, most notably freight trucks. Diesel vehicles comprised about 65 percent of the
medium- and heavy-duty vehicles in California in 2013, as seen in Figure 24.
Figure 24: California Medium-/Heavy-Duty Vehicles Distribution by Fuel Type
Source: Energy Commission and Department of Motor Vehicles
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Figure 25 shows diesel demand for on-road vehicles and rail. While diesel consumption is
projected to continue climbing through 2020, all three diesel demand cases project this trend
to reverse as alternative fuels increase in market share. The projected growth in alternative
fuel HDVs is led primarily by natural gas trucks in freight, as almost 60 percent of transit
vehicles in California are already powered by natural gas. This forecast does not include
Executive Order 13423, (Strengthening Federal Environmental, Energy, and Transportation
Management), but as this executive order is implemented, a further decline in diesel
demand is anticipated.
Figure 25: Preliminary California On-Road and Rail Diesel Demand Forecast
Source: California Energy Commission
The Energy Commission staff will revise the preliminary diesel demand forecast based on
revised transportation energy price forecast and the revised vehicle attribute projections.
Natural Gas
The natural gas vehicle fleet in California is almost exclusively MDVs and HDVs, such as
transit buses and utility trucks. While there are light-duty natural gas vehicles, the only
model available on the U.S. market was discontinued in 2015, and the existing natural gas
stock makes up a very small percentage of the LDV fleet.
Natural gas used for transportation is forecast to experience rapid growth as shown in
Figure 26, primarily due to fuel price advantages of natural gas. Heavy-duty natural gas
vehicle market shares used in the forecast are the same as the published National Petroleum
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Council market shares, which were based on the 2010 EIA fuel price forecast. The 2010 EIA
fuel price forecasts were much more favorable to natural gas, resulting in the rapid growth
of natural gas vehicle market shares over the forecast period.
This preliminary forecast of natural gas for transportation is also included in the natural gas
demand forecast in the Energy Commission’s 2015 Natural Gas Outlook.
Figure 26: Preliminary Transportation Natural Gas Demand Forecast
Source: California Energy Commission
Energy Commission staff will update the natural gas truck market share to reflect the
revised 2015 natural gas and diesel prices. As mentioned above, the Demand Analysis
Office will be updating its diesel price forecast based on the AEO 2015 crude oil forecast.
Likewise, the Supply Analysis Office will update the natural gas price forecast. These
updated price forecasts will be reflected in the revised transportation energy demand
forecasts.
Electricity
Most of the electricity used for transportation in California can be attributed to LDVs, light
rail, and cable cars. The forecast shows an increase in the number of plug-in electric vehicles
for the forecast period, but not enough to make electricity the primary fuel source for LDVs
over the forecast period which ends in 2026. In addition to the projected shift to electric
vehicles, high-speed rail is scheduled to begin operation in 2022, which will further drive
the increase in transportation electricity in the final years of the forecast period.
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High-Speed Rail (HSR)
The California High-Speed Rail Authority (CalHSR) provided the HSR energy consumption
forecast presented in Figure 27 which was developed in support of Connecting California
2014 Business Plan, April 2014. 185 Initially, HSR is slated to run 300 miles from Merced to the
San Fernando Valley, with a projected completion date of 2022. Next, the Bay-to-Basin
section, which extends northward to San Jose, is expected to be completed in 2026. Since this
forecast only estimates out to 2026, staff considered only the initial operating section
(Merced to the San Fernando Valley) of the HSR network for purposes of this forecast.
The HSR forecast has been considered only as an “add-on” to the reference case because the
economic and demographic assumptions used for the California High-Speed Rail Authority
base scenario more closely align with the Energy Commission’s own assumptions. Input
assumptions—including fuel price and income—to CalHSR’s high demand scenario were
not comparable with the input assumptions for the Energy Commission’s input
assumptions for the high energy demand case. The same is true for the low demand cases
for both forecasts. CalHSR’s mid demand scenario is more compatible with the Energy
Commission’s reference case; therefore, that case is the only case considered in the
preliminary forecast and is included to give some indication of what additional electricity
may be needed. In the reference case, HSR forms 10.2 percent of the total transportation
electricity demand in 2022 and going up to 14.4 percent in 2026.
185 http://www.hsr.ca.gov/docs/about/business_plans/BPlan_2014_Business_Plan_Final.pdf.
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Figure 27: Forecasted High-Speed Rail Electricity Consumption
Source: California High-Speed Rail Authority
Figure 28 shows the projected growth in total transportation electricity demand, in the high,
low and the reference cases. To maintain consistency with the Low Demand and High
Demand scenarios, the reference case shows electricity demand if HSR is not operational by
2026, and the reference w/ HSR case assumes that operation remains on schedule starting in
2022. The difference between these two reference cases show the projected contributions of
HSR in the reference demand case.
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Figure 28: Preliminary Forecast of Total Transportation Electricity Demand 186
Source: California Energy Commission
Jet Fuel
California aviation fuels consist primarily of commercial jet fuel, followed by military jet
fuel and aviation gasoline (used in small private planes). Commercial jet fuel dominates
California aviation fuel use, accounting for 91.4 percent of the total over the last decade,
while military jet fuel accounted for 8 percent, and aviation gasoline only 0.6 percent. 187
Figure 29 shows the relative contribution from the various types between 2004 and 2013.
186 The conversion factor from GGE to kWh is 1 GGE = 32.8 kWh.
187 California aviation fuel consumption in California in 2013 amounted to 3,307 million gallons
commercial jet fuel, 242 million gallons of military jet fuel, and 16 million gallons of aviation gasoline.
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Figure 29: Aviation Fuel Consumption by Use and Type
4,500,000,000
4,000,000,000
3,500,000,000
Commercial Jet Fuel Military Jet Fuel Aviation Gasoline
3,000,000,000
Gallons
2,500,000,000
2,000,000,000
1,500,000,000
1,000,000,000
500,000,000
0
2004 2005 2006 2007 2008 2009 2010 2011 2012 2013
Sources: California State Board of Equalization, Defense Logistics Agency, and Petroleum Industry Information Reporting Act
data
Energy Commission analysis shows future consumption of aviation fuels in California will
be driven by changes in demand for airline travel to domestic and foreign destinations
originating from California airports and changes in fuel economy trends for air carriers over
the forecast period. The Energy Commission does not forecast airline passenger activity
within California. Number of passengers getting on the planes, or enplaned passengers,
departing from California determines the jet fuel sold in California. The Federal Aviation
Administration (FAA) tracks historical passenger activity by airport (measured by enplaned
passengers), as well as forecasting growth by each airport. 188 The FAA also develops
estimates of jet fuel consumption for both historical and forecasted periods but only for the
188 Federal Aviation Administration. FAA Aerospace Forecast Fiscal Years 2015-2035. 2015.
https://www.faa.gov/about/office_org/headquarters_offices/apl/aviation_forecasts/aerospace_forecast
s/2014-2035/media/2015_National_Forecast_Report.pdf.
138

United States as a whole. 189 Staff assumed that the relative contribution of foreign
destinations for California airport activity will change in a fashion similar to that of the
United States: a slightly higher ratio of foreign destinations throughout the forecast period.
California enplaned passenger activity is forecast to grow at a rate of 2.5 percent per year,
slightly lower than the near-term historical growth rate of 2.7 percent per year. An
additional 28.9 million passengers will be boarding flights originating in California by 2025
compared to 2014.
Estimates of fuel consumption per passenger vary by class of destination with domestic
destinations averaging less than those for foreign destinations due to the longer flight
distances for most foreign routes. For example, average consumption of jet fuel per
enplaned passenger originating in the United States and headed for a domestic destination
amounted to 18.5 gallons during 2014, while the average for foreign destinations averaged
72.3 gallons per enplaned passenger. The average jet fuel use for all domestic and foreign
destinations was 24.7 gallons per enplaned passenger. California’s average jet fuel use per
enplaned passenger was estimated to be 36.8 gallons during 2014, nearly 49 percent greater
than the U.S. average. This higher rate is due to a greater ratio of foreign destinations for
California enplaned passengers than that of destinations in the United States. Energy
Commission staff used enplaned passenger projections for California airports in conjunction
with per-passenger fuel consumption trends for the United States to derive estimates of
commercial jet fuel demand for California between 2015 and 2025. Figure 30 shows how
commercial jet fuel consumption in California is forecast to grow from 3,357 million gallons
during 2014 to 4,212 million gallons by 2025.
189 Ibid, Table 23, p. 120.
139

Figure 30: Commercial Jet Fuel Consumption
Source: California Energy Commission analysis of FAA historical and forecast data
The preliminary demand forecasts in all sectors except aviation and HSR will be revised
with updates in key inputs such as energy prices and vehicle attributes based on Energy
Commission and EIA updated data.
Alternative and Renewable Fuel and Vehicle Technology Program
Benefits Update
Introduction
As part of its strategy to reduce GHG and criteria emissions from the transportation sector,
the California Legislature created an incentive funding program for the development of
alternative fuel and vehicle technologies with the passage of Assembly Bill 118. This
legislation created the Alternative and Renewable Fuel and Vehicle Technology Program
(ARFVTP), administered by the Energy Commission. With funds collected from vehicle and
vessel registration fees, and vehicle identification plates and smog fees, the ARFVTP
provides up to $100 million per year for projects that will "transform California’s fuel and
vehicle types to help attain the state’s climate change policies." The statute also calls for the
Energy Commission to “develop and deploy technology and alternative and renewable
fuels in the marketplace, without adopting any one preferred fuel or technology.” Assembly
Bill 8 subsequently extended the collection of fees that support the ARFVTP through
January 1, 2024.
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Assembly Bill 109 (Núñez, Chapter 313, Statutes of 2008) requires the Energy Commission to
prepare “an evaluation of research, development, and deployment efforts funded by this
chapter” every two years, in conjunction with the Energy Commission’s IEPR. The
evaluations must include a list of all funded projects, expected benefits from the projects,
overall contributions of the projects toward a portfolio of clean fuels, and obstacles and
recommendations. This section of the 2015 IEPR fulfills the AB 109 reporting requirement
and includes ARFVTP activities and expenditures through June 30, 2015.
Role of the ARFVTP Investment Plan
The Energy Commission allocates ARFVTP funds through preparation and adoption of an
annual investment plan update that identifies the funding priorities for the coming fiscal
year. The funding allocations reflect the potential for each alternative fuel and vehicle
technology to contribute to the goals of the program; the anticipated barriers and
opportunities associated with each fuel or technology; the effect of other entities’
investments, policies, programs, and statutes; and a portfolio-based approach that avoids
adopting any preferred fuel or technology. With the adoption of the 2015-2016 Investment
Plan Update for the Alternative and Renewable Fuel and Vehicle Technology Program (2015-2016
Investment Plan) 190 at its April 2015 Business Meeting, the Energy Commission has
developed and adopted seven Investment Plans.
Description of Funded Projects
As of June 30, 2015, the Energy Commission has issued or proposed roughly $589 million in
ARFVTP funding across 496 agreements that span California. 191 These agreements support a
broad portfolio of fuel types, supply chain phases, and commercialization phases. In most
cases, projects are still in progress: production facilities are still being sited and constructed,
infrastructure is still being installed, and vehicles are still being demonstrated or deployed.
On a dollar basis, 29 percent of the projects have been completed to date.
Table 6 shows ARFVTP investments by primary fuel and program category. Figure 31
shows ARFVTP investments by fuel category and supply chain phase.
190 Smith, Charles, Jacob Orenberg. 2015. 2015-2016 Investment Plan Update for the Alternative and
Renewable Fuel and Vehicle Technology Program Commission Report. California Energy Commission,
Fuels and Transportation Division. Publication Number: CEC-600-2014 -009- CMF.
191 The Energy Commission DRIVE website contains a map of ARFVTP-funded projects in California
http://www.energy.ca.gov/drive/projects/map/index.html
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Table 6: ARFVTP Investments by Primary Fuel Category Through June 30, 2015
Investment Areas
Funding Amount
(in millions)
Percent of Total
(%)
Number of
Awards
Biofuels $164 28 68
Electric Drive $193 33 150
Natural Gas $95 16 168
Hydrogen $99 17 43
Workforce Development $25 4 55
Market & Program Develop. $13 2 12
Total $589 100 496
Source: Energy Commission staff
Figure 31: ARFVTP Investments by Fuel Category and Supply Chain Phase Through
June 30, 2015
$200
$180
$160
$140
$120
$100
$80
$60
$40
$20
$0
Biodiesel
Biomethane
Ethanol/E85
Electric
Hydrogen
Natural Gas
Propane
Workforce
Other
Source: Energy Commission staff
The nearly $600 million in ARFVTP investments are beginning to create meaningful levels
of market penetration for advanced technology fuels, fueling infrastructure and vehicles.
However, given the vast scale of California’s transportation sector, with more than 28
million light-duty passenger vehicles and medium- and heavy-duty trucks and 18 billion
gallons in fuel consumption, the transition to low-carbon and zero-emission vehicles and
fuels remains modest. Listed below are highlights of the ARFVTP funding portfolio to date.
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Building the Foundational Charging and Fueling Infrastructure for Zero-Emission Vehicles
• 7,515 192 installed and planned chargers for plug-in electric vehicles, including 4,175
residential charging points, 2,742 commercial chargers, 718 workplace charging
points, and 119 direct current (DC) fast chargers.
• 34 regional readiness planning grants to help regions throughout the state plan for
electric vehicle deployment, new charging infrastructure, and permit streamlining.
• 49 new or upgraded hydrogen refueling stations that will support the early
commercial deployment of fuel cell electric vehicles by major automakers such as
Toyota, Hyundai, and Honda. California’s hydrogen fueling network is one of the
largest in the world.
Advancing Commercial Development of Low-Carbon Biofuels in California
• 49 projects to promote the production of sustainable, low-carbon biofuels within
California. Most will use waste-based feedstocks, which contribute to some of the
lowest carbon-intensity pathways recognized under the Low Carbon Fuel Standard.
These projects expand California’s ethanol production capacity by 8.8 million gallons
per year, biodiesel production capacity by 59.2 million gallons per year, and
renewable diesel production capacity by 17.9 million gallons per year.
Investing in Advanced-Technology Zero-Emission Trucks
• 42 projects to demonstrate zero- and near-zero-emission advanced technologies and
alternative fuels in a variety of medium- and heavy-duty vehicle applications. These
projects include 30 medium-duty electric drive trucks, 17 medium-duty hydrogen
fuel cell trucks, 5 heavy-duty all electric drayage trucks, 1 heavy-duty fuel cell
drayage trucks, 23 electric school and transit buses, and 8 hydrogen fuel cell buses.
• 22 manufacturing projects for electric drive-related vehicles and components that
will support in-state economic growth while reducing the supply-side barriers for
alternative fuels and advanced technology vehicles.
Capitalizing on Low-Cost, Low-Emission Natural Gas Truck Technologies
• 2,956 natural gas vehicles now or soon-to-be in operation in a variety of applications,
including roughly 2,600 medium- or heavy-duty trucks. Natural gas trucks offer
immediate but modest reductions in carbon and criteria emissions in a cost
effectively. 193
192 Energy Commission staff has revised the units for charging infrastructure from charge points or
charging stations to chargers. Chargers denote a charging pedestal that may have multiple charge
points or connectors. For example, The 2015-2016 Investment Plan cited 9,369 charging stations.
193 The natural gas vehicle voucher rebate program is in transition. Due to falling petroleum and
diesel prices, demand for natural gas trucks has diminished; $4.5 million in natural gas vehicle
143

• 50 natural gas fueling stations to support a growing population of natural gas
vehicles. These include at least five stations that will incorporate low-carbon
biomethane into the dispensed fuel.
Advancing Workforce Training and Development
• Workforce training for 13,674 trainees and more than 600 businesses that will
translate California’s clean technology investments into sustained employment
opportunities.
As shown in Table 7, ARFVTP grants are distributed throughout the state primarily in
proportion to regional population levels. However, the San Joaquin Valley air basin receives
about 14 percent of the funding awards and has 10 percent of the state’s population, while
the South Coast air basin receives 27 percent of program funding and has 44 percent of the
state’s population.
Table 7: Geographic Distribution ARFVTP Funding by Air District
Air District
Total Funding
Amount
($ millions)
Percent of
Total ARFVTP
Funding
Percent of State
Population
Bay Area 96.9 16.5% 18.4%
Monterey 9.4 1.6% 2.0%
Sacramento 24.6 4.2% 3.6%
Santa Barbara 3.0 0.5% 1.1%
San Diego 32.0 5.4% 8.4%
San Joaquin 84.1 14.3% 10.5%
South Coast 158.8 27.0% 44.0%
Ventura 1.3 0.2% 2.2%
Yolo-Solano 16.6 2.8% 0.9%
Other Northern California 16.4 2.8%
8.9%
Other So Cal Districts 4.4 0.7%
Statewide 141.4 24.0% -
Total 588.9 100.0% 100.0%
Source: Energy Commission staff
funding went unused and reverted. In addition, Honda Motor Corporation announced the
cancelation of the Honda CRG, the last light-duty natural gas vehicle offered by a major auto
manufacturer in the United States. The Energy Commission has entered into a new administration
and research contract with the University of California at Irvine to administer this portion of
ARFVTP.
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Table 8 illustrates some of the positive impacts of the ARFVTP on levels of alternative
fueling infrastructure and vehicles in California since the Program was initiated in 2009. The
table shows the percentage increase in fueling infrastructure and some vehicle types from a
2009-2010 baseline.
Table 8: ARFVTP Funding Impacts on Infrastructure and Vehicle Deployment in California
Alternative
Fueling
Infrastructure
Alternative
Fuel Vehicles
Electric
Fuel Area
Existing 2009-2010
Baseline Levels
2,540 charge points
Additions Funded from
ARFVT or AQIP Program
Funding
7,515 charging stations
(residential, public,
Percent
Increase
workplace, DC fast charger)
E85 39 fueling stations 158 fueling stations 405
Natural Gas 443 fueling stations 50 stations 11
Hydrogen 6 public fueling stations 49 fueling stations 800
Electric Cars
(ARB Vouchers)
13,268
(mostly neighborhood
electric vehicles)
(21,000 via ARFVTP)
110,000: Total AQIP*
Electric Trucks 1,409 160 11
Natural Gas Trucks 13,995 2,600 19
Source: Energy Commission staff * Total number of CVRP vouchers issued through AQIP through June 30, 2015. ARFVTP
funding accounts for 19 percent of total CVRP voucher funding.
Summary of ARFVTP Benefits
For the 2015 IEPR, the Energy Commission has contracted with the National Renewable
Energy Laboratory (NREL) 194 to calculate the expected benefits of the ARFVTP consistent
with the statutory requirements of AB 109. Dr. Marc Melaina, principal investigator, and his
team expanded on the methods, data, and timeline developed for the 2014 Benefits
Report. 195 NREL analyzed updated ARFVTP project data for 262 projects totaling $552
million, representing the ARFVTP project portfolio as of June 30, 2015.
NREL used the same methodology in 2015 as in 2014. Because the 2014 IEPR Update
analyzed ARFVTP benefits through the fourth quarter of 2014, the number of new projects
to be assessed for 2015 is modest, as are the 2015 increases in carbon emission reduction and
petroleum reduction.
NREL has developed a framework of four quantifiable benefit categories for petroleum
reduction, GHG emissions reductions, and criteria emissions reductions:
• Baseline Benefits expected to accrue without support from ARFVTP.
300
829
194 California Energy Commission Agreement Number 600-11-002.
195 Melaina, Dr. Marc et al. November 2013. Draft Analysis of Benefits Associated with Projects and
Technologies Supported by the Alternative and Renewable Fuel and Vehicle Technology Program. National
Renewable Energy Laboratory.
145

• Expected Benefits directly associated with vehicles and fuels deployed through
projects receiving ARFVTP funds. Expected benefits are quantified as the most likely
benefits to occur from ARFVTP projects being executed successfully, assuming oneto-one
substitution of the service or technical performance of the new technology
replacing the existing technology. Project categories include vehicles, refueling
infrastructure, and fuel production. NREL evaluated 225 of the 320 total projects
funded as of June 30, 2015, to determine expected benefits.
• Market Transformation Benefits accrue due to the influence of ARFVTP projects on
future market conditions to accelerate the adoption of new technologies. Influences
include increased availability of public electric vehicle supply equipment and
hydrogen refueling stations, consumer incentives for zero-emission vehicles (ZEVs),
investments in ZEV demonstrations and manufacturing facilities, deployment of
next-generation fuel production facilities, and advanced truck demonstrations.
NREL evaluated these seven categories of ARFVTP-funded projects to determine
market transformation benefits.
• Required Carbon Market Growth Benefits: associated with projections of future
market growth trends comparable to those needed to achieve deep reductions in
GHGs by 2050.
For a full list of ARFVTP projects analyzed by NREL for the 2015 IEPR see Appendix D.
Expected Benefits Results
Of the projects NREL analyzed for expected benefits, ARFVTP has invested $155 million (22
projects) in vehicles, $158 million (157 projects) in refueling infrastructure, and $123 million
(40 projects) on fuel production infrastructure. The major new awards since 2014 included 4
electric drive manufacturing projects, 11 medium-duty and heavy-duty zero-emission truck
and bus technology demonstration projects, 4 early stage biofuels demonstrations, and 13
compressed natural gas fueling stations. Figure 32 shows estimated total GHG emissions
reductions across broad project categories. The GHG emission reductions are comparable
among the three categories by 2025, ranging from 0.5 million to 1.1 million metric tons of
carbon dioxide equivalent (MMTCO2e). The steady growth in GHG reductions in the vehicle
category is due largely to electric drive vehicle production and manufacturing projects for
medium- and heavy-duty trucks. The pie charts to the right of the figure indicate the
percentage of cumulative reductions over the period for various project subcategories, with
manufacturing, natural and renewable natural gas, and diesel substitute dominating the
vehicles, fueling infrastructure, and fuel production categories, respectively.
146

Figure 32: Summary of Annual GHG Emissions Reductions Through 2025 From Expected
Benefits of 219 Funded Projects
Source: NREL
Figure 33 shows total petroleum use reductions across these major project categories.
Annual petroleum use reductions by 2025 includes 142 million gallons per year from vehicle
projects, 98 million gallons per year from refueling infrastructure, and about 73 million
gallons from fuel production projects. In sum, petroleum fuel reductions for all three
expected benefit categories approach 313 million gallons per year by 2025.
147

Figure 33: Summary of Annual Petroleum Fuel Reductions From Expected Benefits
Through 2025
Source: NREL
In comparing petroleum fuel and GHG reductions, the refueling infrastructure makes a
larger relative contribution to petroleum fuel reductions than GHG reductions. This is due
largely to ethanol and natural gas refueling stations displacing large volumes of petroleum
fuel, despite the relatively high fuel carbon intensity compared to fuels used in other
projects.
Market Transformation
The Energy Commission’s core mission with ARFVTP is to transform California’s
petroleum-based transportation system into a low-carbon, low-emission transportation
system. Market transformation benefits are as real and tangible as the direct or expected
benefits described earlier. They are, however, based upon more uncertain data and more
hypothetical estimation methods than the expected benefits in terms of GHG reductions and
petroleum use reductions.
Market transformation may be second order benefits that follow from successful deployment
of technologies. For example, the goal in demonstrating a small-scale biofuel production
process would be to validate the technology, production process, and production costs, all
of which are critical to future market success. Yet this important technology validation
would yield only a small volume of low-carbon fuel that is directly attributable to the initial
ARFVTP project grant (expected benefit). A successful demonstration project would
increase the likelihood of larger-scale deployment by the initial company and perhaps by
other companies. A successful demonstration would also provide performance and
potential market data to attract new private or public funding. The magnitude of these
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future benefits is measured by NREL as market transformation benefits. For more
information on the methods used to measure market transformation benefits, see the 2014
IEPR Update. 196
Market Transformation Benefits Results
Market transformation benefits are additive to the expected benefits. Figure 34 shows the
total range of expected and market transformation GHG reduction benefits from ARFVTP
projects, which are projected to range from 3.2 to 5.6 MMTCO2e by 2025. This represents a
modest 300,000 ton increase from the 2014 high case of 5.3 MMTCO2e. Overall, California
expects the suite of adopted transportation sector measures, including the LCFS and the
Advanced Clean Cars program, will result in GHG emission reductions of 23 MMTCO2e in
2020. 197 The largest proportion of these emission reductions are expected to come from the
LCFS program, reducing 15 MMTCO2e in 2020. 198 Significant ongoing public and private
sector investments will be needed to continue developing advanced technologies, lowcarbon
fuels, fueling infrastructure, and vehicles to build consumer and commercial market
acceptance for these products to achieve the needed market growth and associated benefits
represented in the green portion of Figure 34.
196 California Energy Commission. 2015. 2014 Draft Integrated Energy Policy Report Update. Publication
Number: CEC-100-2014-001-CMF. Appendices C and D.
197 California Air Resources Board, First Climate Change Scoping Plan Update, Table 5. “Meeting the
2020 Emissions Target,” May 2014.
198 California Air Resources Board, Low Carbon Fuel Standard Advisory Board Meeting, staff
presentation, May 19, 2014, as reported by Jim McKinney, staff presentation at the June 12, 2014,
Integrated Energy Policy Report workshop.
149

Figure 34: GHG Reductions From Expected and Market Transformation Benefits in
Comparison to Needed Market Growth Benefits
Source: NREL
Public Health and Social Benefits
Reducing petroleum fuel use through investments in alternative technology fuels and
vehicles reduces carbon and criteria emissions. These emission reductions also create a
series of public health and other social benefits, including job creation benefits.
Public health impacts in the San Joaquin Valley and South Coast Air Basin from
transportation sector emissions are significant. 199 Reducing NOx and PM2.5 emissions
creates the most important public health benefits. NOx emissions combine with volatile
organic compounds and sunlight to form ozone. The public health impacts from ozone
pollution include increased mortality due to respiratory diseases; increased incidences of
199 See, for example, U.S. Environmental Protection Agency. 2002. Health Assessment Document for
Diesel Engine Exhaust. Prepared by the National Center for Environmental Assessment, Washington,
DC, for the Office of Transportation and Air Quality; EPA/600/8-90/057F, http://www.epa.gov/ncea;
and American Lung Association, State of the Air City Rankings, 2013
http://www.stateoftheair.org/2013/city-rankings/. Note that 6 of the 10 worst cities in the United
States for ozone pollution are in California’s Central Valley and South Coast regions, while 7 of the 10
worst cities for particulate matter pollution are in these same regions.
150

heart attacks, strokes, and heart disease; low birth weight and developmental delays in
children, and substantial increases in rates of asthma and other respiratory diseases.
Children and the elderly are especially susceptible to ozone-related health impacts. 200 At this
time, there is insufficient data from the ARFVTP data set to assess public health benefits of
reduced NOx emissions from California’s transportation sector.
The health benefits of reduced PM2.5 emissions include reduced premature deaths and
morbidity, including avoided instances of upper and lower respiratory symptoms,
bronchitis, asthma exacerbation, hospital and emergency room visits, and work-loss days.
NREL calculates the benefits of reduced PM2.5 emissions by quantifying the emissions
reductions and then monetizing the public health benefits on a geographic basis.
Reductions in PM2.5 emissions are estimated for electric-drive vehicles, primarily light-duty
PHEVs, BEVs, and FCEVs, as well as some medium-duty PHEVs and BEVs. The health
benefits from reduced PM2.5 tailpipe emissions are due primarily to reduced premature
deaths and morbidity.
These reductions range from 2 to 5 tons per year in 2025. 201 The monetized values of these
PM2.5 reduction benefits range from $4 million to $8 million per year, with the benefit-perunit
reduction (million dollars per ton PM2.5 reduced, or $M/ton) varying significantly by
county and averaging to $1.7 million per ton across all counties.
Job Creation and Workforce Training Benefits
While the primary policy goals of ARFVTP are to reduce petroleum fuel use and reduce
carbon and criteria emissions, important social benefits such as economic development and
job creation are also created.
To estimate job creation benefits, staff administered an electronic survey to recipients of all
new technical project grants awarded since early 2013 when the last IEPR jobs survey was
administered. Table 15 survey results incorporate the previous survey results with the 2015
IEPR survey results. Staff did not include job training, natural gas truck buydown, research,
technical support, and program support grants and contracts in the survey. The response
rate was high, with just a handful of grantees not responding.
The survey requested both short-term and long-term job creation estimates. Short-term jobs
were defined as lasting 18 months or less and assumed to relate to project development,
engineering and design, and construction phases. Long-term jobs are assumed to be greater
200 U.S. Environmental Protection Agency, Integrated Science Assessment for Ozone and Related
Photochemical Oxidants, 2013. EPA/600/R-10/076F.
201 These projected decreases in PM2.5 emissions from the transportation sector reflect only the
emissions reductions attributable to Expected Benefits from direct ARFVTP investments as reported
in the NREL Benefits Report.
151

than 18 months and relate to project operations, manufacturing, maintenance, sales and
administration. The survey includes jobs created by the primary grantee and all major
partner and subcontractor firms listed in the grant agreements. It does not include jobs
created upstream for equipment supply chains or by secondary multipliers. Although 29
percent of ARFVTP projects are now complete, the majority of the program projects are still
in the development or construction phases. This means that most job creation benefits
continue to be projected estimates, rather than final confirmed figures from completed
projects.
Table 9 shows the estimated total number of jobs created through ARFVTP grant awards.
Short-term jobs total 4,144, and long-term jobs total 3,712. Cumulative job creation to date is
estimated to be 7,856. Construction-related jobs are the biggest category for short-term jobs,
accounting for 35 percent of the total. For long-term jobs, manufacturing and operations and
maintenance-related jobs predominate, representing 45 percent and 13 percent of the total.
Table 9: Projected Job Creation by Category
Administrative Manufacturing Construction Engineering
Operation
and Other Total
Maintenance
Short-term 478 701 1,486 1,125 224 130 4,144
Long-term 437 512 164 1,696 482 421 3,712
Totals 914 1,213 1,650 2,822 706 550 7,856
Source: Energy Commission staff (Note: There is a slight tally error due to rounding).
Workforce Training Benefits
The program also aligns clean technology investments with economic development. The
program has invested about $25 million to help provide training for more than 13,600
individuals, 600 businesses, and 14 municipalities to support all aspects of alternative fuel
technologies. The program has also provided funding to community colleges in Northern,
Central, and Southern California for curriculum development, train-the-trainer programs,
essential equipment needs, and other approved activities to support alternative fuel and
advanced vehicle technology training and education. California community colleges
continue to lead in the training of alternative fuels and advanced vehicle technologies in
California by focusing on employer needs within each community and having those
employers support new and existing training programs. Funding to the Employment
Training Panel delivers training across multiple fuel and technology types and requires
employers to commit matching funds.
Recommendations
Alternative and Renewable Fuel and Vehicle Technology Program
• Continue to monitor utility electric vehicle proposals. The Energy Commission
should monitor the CPUC decisions on California’s three largest investor-owned
utilities applications for installation of up to 60,000 electric vehicle chargers
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throughout California. If approved, this large-scale installation will need to be
coordinated with ongoing Alternative and Renewable Fuel and Vehicle Technology
Program (ARFVTP) EV installation investments to ensure the most efficient and
effective build-out of statewide EV charging infrastructure.
• Continue ARFVTP investment in a portfolio of projects. Achieving the Governor’s
ambitious 50 percent petroleum reduction goal by 2030, the Energy Commission
must continue to evaluate and assess its current technology investments and adjust
annual ARFVTP funding allocations in response to changing markets. The Energy
Commission’s policy of funding a portfolio of alternative fuels and advanced vehicle
technologies recognizes that pursuing a single fuel type or vehicle technology will
not achieve California’s 50 percent petroleum reduction goal.
• California’s sustainable freight strategy and California’s ports initiative offer
critical opportunities to reduce greenhouse gas emissions. The Energy Commission
should continue to collaborate with California Air Resources Board, California
Department of Transportation, the Governor’s Office of Business and Economic
Development, and others to identify opportunities to leverage ARFVTP funds to
maximize emission reductions and improve economic competitiveness at
California’s ports and freight sectors.
• Support the updated 2015 ZEV Action Plan. Continue close involvement and
support of the 2015 and future ZEV Action Plans. The 2015 ZEV Action Plan offers
opportunities for ARFVTP to continue supporting the expanding use of ZEV
technologies in the medium- and heavy-duty truck and bus sectors.
• Continue diversity and disadvantaged community outreach efforts under the
ARFVTP. The ARFVTP should continue outreach to small businesses, women-, and
disabled veteran-, minority-, and LGBT-owned businesses to increase their
participation in ARFVTP funding opportunities. The ARFVTP should also continue
actions to increase program participation rates of California’s economically and
environmentally disadvantaged communities.
Alternative and Renewable Fuel and Vehicle Market Expansion
• Expand zero-emission-vehicle purchase incentives to disadvantaged communities.
California should continue to provide greater allocation of vehicle purchase
incentives to disadvantaged communities and low- and middle-income people to
expand the zero-emission-vehicle market in California.
• Collaborate with other states and nations to expand market. California should
continue to coordinate and collaborate with other states and nations to promote and
expand renewable fuels and alternative vehicle markets.
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CHAPTER 5:
Electricity Demand Forecast
Background
Since the restructuring of California’s electric industry in the late 1990s under Assembly Bill
1890 (Brulte, Chapter 854, Statutes of 1996), electricity infrastructure planning in California
has been split among the California Energy Commission, the California Public Utilities
Commission (CPUC), and the California Independent System Operator (California ISO)
(collectively the “energy agencies”). Three major cyclical processes now form the core of
electric infrastructure planning:
• The long-term forecast of energy demand produced by the Energy Commission as
part of its biennial Integrated Energy Policy Report (IEPR)
• The biennial Long Term Procurement Plan proceeding (LTPP) conducted by the
CPUC
• The annual Transmission Planning Process (TPP) performed by the California ISO.
More recently, with the adoption of new energy and environmental policy goals and the
emergence of diverse supply and demand-side technologies, it has become apparent that
closer collaboration among the energy agencies and alignment of these processes are
needed. One outgrowth of collaboration was the establishment of the management-level
Joint Agency Steering Committee to ensure regular communication on planning
coordination and to support agency leadership in its decision on a single forecast set for
planning. In addition, an interagency process alignment technical team was created as a
forum for planning staff from the Energy Commission, the CPUC, and the California ISO to
discuss technical issues and improve infrastructure planning coordination.
The agencies also agreed on an annual process to be performed in the fall of each year to
translate the single forecast set into assumptions and scenarios to be used in infrastructure
planning activities in the coming year. Work is now expanding from energy efficiency and
demand response to properly accounting for other load-modifying assumptions included in
the Energy Commission’s demand forecast; for example, new demand response strategies,
time-of-use rates, customer-side distributed generation, combined heat and power,
distributed energy storage, and electric vehicles. 202
202 Alignment of Key Infrastructure Planning Processes by CPUC, CEC and CAISO Staff, December 23,
2014, http://www.energy.ca.gov/assessments/documents/CEC-CPUC-
ISO_Process_Alignment_Text.pdf.
154

The Energy Commission prepares 10-year forecasts of electricity consumption and peak
electricity demand for California and for individual utility planning areas and forecast
zones within the state. The California Energy Demand 2016−2026, Preliminary Electricity
Forecast (CED 2015 Preliminary) is described here; a revised/final version of this forecast will
be developed later this year and incorporated in the final version of the 2015 IEPR. The
electricity results for CED 2015 Preliminary were presented at an IEPR workshop on July 7,
2015, and a full forecast report is posted on the Energy Commission’s website. 203 The
preliminary end-user natural gas forecast developed by staff in conjunction with electricity
is summarized in Chapter 6.
The CED 2015 Preliminary includes three cases designed to capture a reasonable range of
demand outcomes over the next 10 years. The high energy demand case incorporates
relatively high economic/demographic growth and climate change impacts, and relatively
low electricity rates and self-generation impacts. The low energy demand case includes lower
economic/demographic growth, higher assumed rates, and higher self-generation impacts.
The mid case uses input assumptions at levels between the high and low cases. These
scenarios are referred to as baseline cases, meaning they do not include additional achievable
energy efficiency (AAEE) savings.
Summary of Changes to the Forecast
The following discusses key changes relative to the last adopted forecast, California Energy
Demand Updated Forecast, 2015−2025 (CEDU 2014). 204 In an effort to make the demand
forecast more useful to resource planners, the CED 2015 Preliminary uses a revised
geographic scheme for planning areas and climate zones, more closely based on California’s
balancing authority areas. The CED 2015 Preliminary includes 20 climate zones, compared to
16 in previous forecasts. This new scheme, which is described in detail in Chapter 1 of the
forecast report for the CED 2015 Preliminary, will also be used in the revised version of this
forecast.
As part of the continuing effort to comprehensively capture the impacts of energy efficiency
initiatives, staff invested considerable effort over the last year reassessing and updating
building and appliance standards savings impacts calculated within the forecast models.
The CED 2015 Preliminary also includes estimated efficiency impacts not included in the
CEDU 2014, from 2015 investor-owned utility programs and from 2014 programs
administered by publicly owned utilities.
203 http://docketpublic.energy.ca.gov/PublicDocuments/15-IEPR-
03/TN205141_20150623T153206_CALIFORNIA_ENERGY_DEMAND_20162026_PRELIMINARY_EL
ECTRICITY_FOREC.pdf.
204 http://www.energy.ca.gov/2014publications/CEC-200-2014-009/CEC-200-2014-009-CMF.pdf.
155

The most significant change compared to previous forecasts, in terms of peak demand and
retail sales, comes through the projections for self-generation. The CED 2015 Preliminary
incorporates refinements to staff’s predictive models for self-generation, including the
introduction of tiered residential rates for the photovoltaic (PV) system adoption model. As
a result, residential PV impacts are significantly higher than in the CEDU 2014. 205
With the passage of Senate Bill 350 (De León, 2015) and Assembly Bill 802 (Williams, 2015)
(AB 802), future iterations of the electricity demand forecast will include greater emphasis
on detailed, localized, and sector-specific analysis of energy demand trends. This more
granular analysis will be needed to support the state’s policy goals including setting,
assessing, and advancing energy efficiency goals discussed in Chapter 1 and to help
optimize the integration of increasing amounts of renewable energy discussed in Chapter 2.
Among other provisions, AB 802 clarifies the Energy Commission’s authority to collect
energy usage data needed to support implementation of the various provisions in the bill.
As result, the Energy Commission will build its capabilities to manage and provide rigorous
analysis of the data in support of energy demand forecasts.
California Energy Demand Forecast Results
A comparison of the CED 2015 Preliminary baseline statewide electricity forecast for selected
years (five-year increments starting in 2015 plus the final year of the forecast) with the mid
case from the CEDU 2014 is shown in Table 10. Consumption in the CED 2015 Preliminary
mid demand case is very similar to the CEDU 2014 mid case, although consumption grows
at a slightly lower rate through 2025 mainly as a result of a decline in 2014 due to higher
actual electricity rates compared to projections used in the previous forecast. The new high
demand case is actually lower than the new mid in the early years of the forecast because
the economic projections of manufacturing output from Global Insight—the key driver for
industrial electricity consumption—are lower during this period. 206 The CED 2015
Preliminary statewide peak demand (the sum of the individual planning area coincident
peaks) 207 grows at a lower rate from 2014−2025 in the mid case compared to the CEDU 2014
because of the higher self−generation forecast.
205 Using a tiered structure within the PV predictive model means a higher marginal benefit for PV
adoption, especially for high users.
206 Such inconsistencies can occur when using more than one vendor for the economic scenarios.
CED 2015 Preliminary uses Global Insight projections for the high demand case and Moody’s
projections in the mid and low cases.
207 The state’s coincident peak is the actual peak demand for the whole system, while noncoincident
peak is the sum of actual peaks for individual planning areas, which may occur at different times.
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Table 10: Comparison of CED 2015 Preliminary and CEDU 2014 Mid Case Demand Baseline
Forecasts of Statewide Electricity Demand
CEDU 2014 Mid
Energy
Demand
Consumption (GWh)
CED 2015 CED 2015
Preliminary Preliminary Mid
High Energy Energy
Demand Demand
CED 2015
Preliminary
Low Energy
Demand
1990 227,576 227,576 227,576 227,576
2000 260,399 260,400 260,400 260,400
2013 277,140 277,023 277,023 277,023
2015 284,305 283,008 283,098 280,794
2020 301,290 305,119 298,838 293,815
2025 320,862 329,174 319,623 312,611
2026 −− 333,930 323,628 316,362
Average Annual Growth Rates
1990−2000 1.36% 1.36% 1.36% 1.36%
2000−2013 0.48% 0.48% 0.48% 0.48%
2013−2015 1.28% 1.07% 1.09% 0.68%
2013−2025 1.23% 1.45% 1.20% 1.01%
2013−2026 -- 1.45% 1.20% 1.03%
Noncoincident Peak (MW)
CEDU 2014 Mid
Energy
Demand
CED 2015
Preliminary
High Energy
Demand
CED 2015
Preliminary Mid
Energy
Demand
CED 2015
Preliminary
Low Energy
Demand
1990 47,543 47,348 47,348 47,348
2000 53,702 53,755 53,755 53,755
2014* 62,454 62,518 62,517 62,517
2015 63,459 63,914 63,521 63,204
2020 67,253 67,706 66,321 64,556
2025 70,644 71,271 68,924 66,178
2026 -- 71,882 69,314 66,371
Average Annual Growth Rates
1990−2000 1.23% 1.28% 1.28% 1.28%
2000−2014 1.08% 1.08% 1.08% 1.08%
2014−2015 1.61% 2.23% 1.61% 1.10%
2014−2025 1.13% 1.20% 0.89% 0.52%
2014−2026 -- 1.17% 0.86% 0.50%
Actual historical values are shaded.
*Weather normalized: CEDU 2014 uses a weather-normalized peak value derived from
the actual 2014 peak for calculating growth rates during the forecast period.
Source: California Energy Commission, Demand Analysis Office, 2015.
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Projected statewide electricity consumption for the three CED 2015 Preliminary baseline
cases and the CEDU 2014 mid demand forecast is shown in Figure 35. By 2025, consumption
in the new mid scenario is projected to be 0.4 percent lower than the CEDU 2014 mid case,
around 1,000 gigawatt-hours (GWh). Annual growth from 2013−2025 for the CED 2015
Preliminary forecast averages 1.45 percent, 1.20 percent, and 1.01 percent in the high, mid,
and low cases, respectively, compared to 1.23 percent in the CEDU 2014 mid case.
Figure 35: Statewide Baseline Annual Electricity Consumption
360,000
340,000
320,000
300,000
280,000
GWh
260,000
240,000
220,000
CED 2015 Preliminary High Demand
CEDU 2014 Mid Demand
CED 2015 Preliminary Mid Demand
CED 2015 Preliminary Low Demand
Historical
200,000
1990
1992
1994
1996
1998
2000
2002
2004
2006
2008
2010
2012
2014
2016
2018
2020
2022
2024
2026
Source: California Energy Commission, Demand Analysis Office, 2015.
Projected CED 2015 Preliminary peak demand for the three baseline scenarios and the CEDU
2014 mid demand peak forecast is shown in Figure 36. By 2025, statewide peak demand in
the new mid scenario is projected to be 2.4 percent lower than the CEDU 2014 mid case.
Annual growth rates from 2014−2025 for the CED 2015 Preliminary scenarios average 1.20
percent, 0.89 percent, and 0.52 percent in the high, mid, and low scenarios, respectively,
compared to 1.13 percent in the CEDU 2014 mid case. Higher projected self-generation from
residential PV adoption reduces the growth rate in the new mid case compared to the CEDU
2014.
158

Figure 36: Statewide Baseline Annual Noncoincident Peak Demand
80,000
75,000
70,000
65,000
60,000
55,000
MW
50,000
45,000
40,000
35,000
CED 2015 Preliminary High Demand
CEDU 2014 Mid Demand
CED 2015 Preliminary Mid Demand
CED 2015 Preliminary Low Demand
Historical
30,000
1990
1992
1994
1996
1998
2000
2002
2004
2006
2008
2010
2012
2014
2016
2018
2020
2022
2024
2026
Source: California Energy Commission, Demand Analysis Office, 2015.
The higher forecast for self-generation also has a significant impact on projected statewide
retail electricity sales, as shown in Figure 37. The CED 2015 Preliminary low and mid cases
are markedly lower than the CEDU 2014 mid case throughout the forecast period. By 2025,
sales in the CED 2015 Preliminary mid case are projected to be more than 13,000 GWh (4.5
percent) lower than in the CEDU 2014 mid case. Annual growth from 2013−2025 for the CED
2015 Preliminary scenarios averages 1.01 percent, 0.68 percent, and 0.42 percent in the high,
mid, and low demand cases, respectively, compared to 1.06 percent in the CEDU 2014 mid
case.
159

Figure 37: Statewide Baseline Retail Electricity Sales
320,000
300,000
280,000
260,000
GWh
240,000
220,000
CEDU 2014 Mid Demand
CED 2015 Preliminary High Demand
CED 2015 Preliminary Mid Demand
CED 2015 Preliminary Low Demand
Historical
200,000
1990
1992
1994
1996
1998
2000
2002
2004
2006
2008
2010
2012
2014
2016
2018
2020
2022
2024
2026
Source: California Energy Commission, Demand Analysis Office, 2015.
Historical and projected peak reduction impacts of self-generation for the three CED 2015
Preliminary demand cases and the CEDU 2014 mid case are shown in Figure 38. Selfgeneration
is projected to reduce peak load by more than 6,800 megawatts (MW) in the new
mid case by 2025, an increase of more than 2,000 MW compared to the CEDU 2014.
160

Figure 38: Statewide Self-Generation Peak Reduction Impact
8,000
7,000
6,000
5,000
4,000
CED 2015 Preliminary Low Demand
CED 2015 Preliminary Mid Demand
CED 2015 Preliminary High Demand
CEDU 2014 Mid Demand
Historical
MW
3,000
2,000
1,000
0
2000
2002
2004
2006
2008
2010
2012
2014
2016
2018
2020
2022
2024
2026
Source: California Energy Commission, Demand Analysis Office, 2015.
Electricity consumption impacts of self-generation for the three CED 2015 Preliminary
demand cases and the CEDU 2014 mid case are shown in Figure 39. Consumption met
through self-generation is projected to reduce retail sales by more than 35,000 GWh in the
new mid case by 2025, an increase of around 12,000 GWh compared to the CEDU 2014 mid
case in 2025.
161

Figure 39: Statewide Self-Generation Consumption Impact
40,000
35,000
30,000
25,000
20,000
CED 2015 Preliminary Low Demand
CED 2015 Preliminary Mid Demand
CED 2015 Preliminary High Demand
CEDU 2014 Mid Demand
Historical
GWh
15,000
10,000
5,000
0
1990
1992
1994
1996
1998
2000
2002
2004
2006
2008
2010
2012
2014
2016
2018
2020
2022
2024
2026
Source: California Energy Commission, Demand Analysis Office, 2015.
The Impacts of Climate Change
CED 2015 Preliminary incorporates the potential impact of climate change on both electricity
consumption and peak demand using temperature scenarios developed by the Scripps
Institution of Oceanography (Scripps). (For more information on the model Scripps used,
see Chapter 9, Research on Climate Impacts to the Electricity System). Consumption effects
are estimated through projected changes in the number of annual heating and cooling
degree days, 208 while peak demand impacts are simulated through increases in annual
maximum daily average temperatures. Electricity consumption is affected by both heating
and cooling degree days, so the effect of increases in the average annual number of cooling
degree days as a result of climate change is tempered by a decreasing average number of
heating degree days (since both minimum and maximum temperatures increase). Among
numerous climate change scenarios run by Scripps, staff chose scenarios that resulted in an
average temperature impact over all scenarios for the mid demand case and in a relatively
high temperature impact for the high demand case. The low demand case assumed no
climate change impacts.
Figure 40 shows the projected statewide impacts of climate change in the mid and high
demand cases on electricity consumption. In the mid case, the impact of projected increases
208 Heating and cooling degree days are determined by the difference between the daily average
temperature and a reference temperature (for example, 65 degrees). The number of days are summed
for a given year. An average temperature below the reference temperature adds to heating degree
days and an average above the reference temperature adds to cooling degree days.
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in cooling degree days is offset almost completely by the impact of decreasing heating
degree days, so that electricity consumption increases by only 60 GWh in 2026. Underlying
this relatively small net impact is a more significant shift in consumption from cooler
months to warmer months. 209
Figure 40: Climate Change Energy Consumption Impacts
1,400
1,200
1,000
800
High Demand
Mid Demand
600
GWH
400
200
-
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
Source: California Energy Commission, Demand Analysis Office, 2015
Figure 41 shows the projected statewide impacts of climate change on peak demand in the
mid and high demand cases. In the mid-case, peak demand increases by around 650 MW by
the end of the forecast period.
209 In 2026, consumption in the warmer months is projected to increase by around 750 GWh while
consumption in the cooler months drops by almost 700 GWh.
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Figure 41: Climate Change Peak Demand Impacts
1,200
1,000
800
600
High Demand
Mid Demand
MW
400
200
-
2015
2016
2017
2018
2019
2020
2021
2022
2023
2024
2025
2026
Source: California Energy Commission, Demand Analysis Office, 2015
The impacts are lower than in the California Energy Demand 2014-2024 Final Forecast 210 partly
because the maximum temperature increases are not as high over the 10 years in both the
mid and high cases and, particularly in the mid case for consumption, because there is a
larger relative increase in minimum temperatures. This may be a function of the choice of
temperature scenarios or an overall change in the scenarios.
Energy Commission staff will continue to refine methods used to analyze the impact of
climate change on the distribution of temperature and its relationship between the “1 in 10”
(extreme weather) and “1 in 2” (normal weather) peak demand. Ongoing work continues
with Scripps to develop a temperature distribution for all the scenarios and to test using this
to develop climate change impacts rather than relying on discrete scenarios.
Plans for the Revised Forecast
The revised version of this forecast, to be presented at an IEPR workshop on December 3,
2015, will incorporate complete electricity sales and self-generation data for 2014. In
210 http://www.energy.ca.gov/2013publications/CEC-200-2013-004/CEC-200-2013-004-V1-CMF.pdf.
164

addition, summer hourly loads for 2015 will be used to develop weather-normalized
peaks 211 for each utility planning area as starting points for the peak forecasts.
Staff plans to include projected AAEE savings for both investor- and publicly owned
utilities in the revised forecast to develop a managed forecast for planning purposes. A new
method to assess publicly owned utilities’ AAEE will be developed, since traditionally only
committed publicly owned utility efficiency was included in the demand forecast.
Stakeholder input through the Demand Analysis Working Group 212 will be used to guide
the development of AAEE alternative scenarios.
A new electric vehicle forecast, based on recent surveys, will be incorporated in the revised
forecast. CED 2015 Preliminary uses an updated version of the forecast used for CEDU 2014.
Recent rate proceedings at the CPUC indicate that rate tiers are likely to be flattened. Energy
Commission staff plans to incorporate such a structure in the revised forecast, which will
likely result in a lower forecast for PV adoption. Given the increasing importance of PV,
modeling techniques will also be a topic of discussion within the Demand Analysis Working
Group. Based on these discussions, staff may make additional modifications to the PV
predictive model for the revised forecast (if time allows) or for future IEPR forecasts.
Recommendations
• Continue efforts to align agency planning cycles. Energy Commission staff
continues to work with the California Public Utilities Commission (CPUC) and the
California Independent System Operator to ensure the alignment of planning cycles
coincides. The Energy Commission should broaden efforts to include greater
visibility for all load-modifying assumptions in the forecast, not only energy
efficiency and demand response. Also, the Energy Commission should continue to
study impacts to the forecast from recent CPUC decisions on time-of-use rates.
• Develop a managed forecast that includes Additional Achievable Energy
Efficiency (AAEE) for resource planners. Working with stakeholders, the Energy
211 Weather normalized peak adjusts annual “yearly” peak loads to represent a peak load under typical
summer weather conditions; they factor out the variations in weather allowing for comparison of
peak loads over time.
212 The Demand Analysis Working Group’s technical stakeholder group was established to provide
the opportunity to discuss forecast issues, data, and methods and to suggest changes to the existing
forecasting process. The Energy Commission, California Public Utilities Commission, the California
Independent System Operator, investor-owned utilities, and publicly owned utilities participate,
together with other organizations including ratepayer, industry, and environmental advocates, and
other interested professionals.
165

Commission should develop AAEE alternative scenarios to include in the overall
managed forecast.
• Address increasing photovoltaic (PV) with stakeholders. The Energy Commission
should hold discussions with stakeholders to address the impact of PV on the
forecast, how to make modifications to the PV predictive model, and options for
procuring installation data needed to improve predictive modeling.
• Define data needs for greater granularity in the demand forecast. The Energy
Commission should work with utility resource planners and stakeholders to
determine what data will be needed for further forecast granularity to support
resource planning needs as well as Senate Bill 350 goals. Methods should be
developed for procuring the data. Methods should be developed for procuring the
data periodically and efficiently and determining what analytical, physical, and staff
resources are required to develop and execute a more granular forecast.
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CHAPTER 6:
Natural Gas
Natural gas provides a flexible energy source for a wide number of applications, including
support for intermittent renewables, and is used in California for generating electricity,
cooking, and space heating to transportation. While natural gas provides a relatively lowcarbon
fuel source when compared to other fossil fuels used for electricity generation or
transportation, recent studies indicate that in certain circumstances methane leakage can
reduce the climate benefits of switching to natural gas. This is because natural gas is
composed primarily of methane, a potent greenhouse gas (GHG). Many research efforts are
aimed at better understanding the leakage rates and these tradeoffs. There may be
opportunities to reduce GHG emissions by converting biomass to renewable biogas or
biomethane for use as a replacement for petroleum-based natural gas in transportation,
electricity generation, and end-use consumption. Protecting public safety continues to be
another important focus in managing the natural gas system.
Assembly Bill 1257 (Bocanegra, Chapter 749, Statutes of 2013) directs the Energy
Commission to explore the strategies and options for using natural gas, including biogas, to
maximize the benefits of natural gas. The highlights of the Energy Commission staff’s
analysis are presented in this chapter. Topics include pipeline safety, effects of federal
regulations and renewables integration, combined heat and power (CHP), natural gas as a
transportation fuel, end-use efficiency, low-emission biomethane, and GHG emissions
associated with the natural gas system. This chapter also summarizes Energy Commission
staff’s analysis of projected natural gas prices, production, and demand, as detailed in the
forthcoming 2015 Natural Gas Outlook.
Assembly Bill 1257 Report
In response to AB 1257 direction, the Energy Commission identified strategies to maximize
the environmental and societal benefits of natural gas and reports on its findings in this 2015
Integrated Energy Policy Report (IEPR). Energy Commission staff developed a report that
addressed the following areas relating to natural gas:
• Natural gas pipeline infrastructure, storage, and reliability
• Natural gas for electric generation
• Combined heat and power using natural gas
• Natural gas as a transportation fuel
• End-use efficiency applications using natural gas for heating and cooling, water heating,
and appliances
• Natural gas and zero-net-energy (ZNE) buildings
• Other natural gas low emission resources and biogas
167

• GHG emissions associated with the natural gas system.
Energy Commission staff released a draft Strategies to Maximize the Benefits Obtained from
Natural Gas as an Energy Source report in mid-September 2015, and held a workshop
September 21, 2015, to provide stakeholders an opportunity to comment on it. A discussion
of the major topic areas, as well as a summary of the feedback received at the workshop, is
provided below.
Natural Gas Pipeline Safety and Infrastructure
California consistently ranks as the second highest gas-consuming state in the United States,
with daily natural gas demand ranging from a little more than 6 billion cubic feet per day to
as high as 11 billion cubic feet per day, depending on the time of year. 213 Increased demand
and the opening of new production areas in recent years have provided California with
access to diverse natural gas sources. The immediate gas infrastructure challenges California
faces relate to pipeline safety, Southern California infrastructure enhancements, and
potential exports to Mexico along the pipelines east of California.
As a result of the pipeline explosion in San Bruno on September 9, 2010, 214 the California
Public Utilities Commission (CPUC) formed an Independent Review Panel of experts to
gather and review facts and make recommendations to Pacific Gas and Electric (PG&E) and
the CPUC. 215 The report determined that lapses in pipeline safety led to the San Bruno
explosion. Key among the recommendations was that PG&E review its integrity
management threat assessment method, ensure capture of all relevant pipeline design data,
improve and apply risk management, improve its automated control and monitoring
systems, and modify its corporate culture so that safety is emphasized over financial
performance. The panel’s recommendations for the CPUC form the cornerstone of a
comprehensive effort launched by the CPUC to create a culture where safety permeates all
of its regulatory activity. A natural gas system that does not satisfy the requirements of the
Public Utilities Code cannot meet California’s future need for natural gas.
Early in 2011, acting on a recommendation from the National Transportation Safety Board,
the CPUC’s Executive Director ordered all four of California’s investor-owned natural gas
utilities to produce “traceable, verifiable and complete records” to validate minimum
213 California Gas and Electric Utilities. 2014 California Gas Report. 2014.
http://www.pge.com/pipeline_resources/pdf/library/regulatory/downloads/cgr14.pdf, p.31.
214 A segment of a 30-inch gas transmission line exploded and took the lives of eight people, injured
58 others, destroyed 38 homes, and damaged 70 other homes.
http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M150/K539/150539121.PDF.
215 California Public Utilities Commission. Report of the Independent Review Panel: San Bruno Explosion.
Decision 13-10-024. October 2013. http://www.cpuc.ca.gov/NR/rdonlyres/85E17CDA-7CE2-4D2D-
93BA-B95D25CF98B2/0/cpucfinalreportrevised62411.pdf.
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acceptable operating pressure on transportation pipelines located in heavily populated
areas. Initial response revealed that only Southwest Gas (a Lake Tahoe area utility) believed
it possessed records for all its pipeline segments pertinent to the National Transportation
Safety Board recommendation. 216 The passage of Senate Bill 705 (Leno, Chapter 522, Statutes
of 2011) reinforced this by establishing that “[i]t is the policy of the state that the [California
Public Utilities]Commission and each gas corporation place safety of the public and gas
corporation employees as the top priority” and by requiring utilities to submit safety plans.
These plans became known as Pipeline Safety Enhancement Plans (PSEPs).
Implementation of the PSEPs continues in 2015. As of August 2014, PG&E completed
pressure validation of its 6,750 mile transmission pipeline system and hydrostatically tested
more than 565 miles of pipeline. It also replaced 90 miles of pipeline and expects its PSEP to
be complete in 2017. 217 Not all has gone smoothly for PG&E since the San Bruno incident. A
number of dig-in rupture events have occurred because of inadequate information in the
hands of construction work crews. PG&E also committed a serious error in the information
provided to the CPUC in asking to restore operating pressure on Line 147, incurring a
$14.35 million fine in December 2013 related to having misled the CPUC about welds on six
segments of the line.
Southern California Gas (SoCalGas) has reported that it was able to find records for about
245 miles of the 385 miles of pipeline initially thought to have to be strength-tested or
replaced. 218 The PSEP work for the Sempra utilities is scheduled to be completed by the end
of 2015, although work on the mainline into San Diego (Line 1600) will be delayed until the
CPUC acts on an application to loop that line so that the existing line can be taken out of
service without creating reliability problems. 219
In approving the PSEPs, the CPUC has ruled that SoCalGas/SDG&E shareholders should
“absorb the portion of the Safety Enhancement costs that were caused by any prior
imprudent management,” the costs of pressure testing where the company cannot produce
216 The National Transportation Safety Board letter can be found at
http://www.ntsb.gov/safety/safety-recs/recletters/P-10-002-004.pdf, and the Executive Director’s order
was ratified by the Commission by resolution on January 13, 2011.
217 August 14, 2014, letter from Paul Clanon, Executive Director CPUC, to National Transportation
Safety Board Acting Chairman Christopher A. Hart.
218 December 5, 2014, Letter of Sempra’s Tamara Rasberry in Docket No. 15-IEPR-04 – “AB1257
Natural Gas Act Report.”
219 A. 14-12-015, “Chapter III Description of PSRMA Costs Prepared Direct Testimony of Richard D.
Phillips,” p. 3 and p. 11.
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ecords, and for pipelines it chooses to replace rather than test. 220 PG&E’s rate recovery also
was significantly less than requested, with the CPUC disallowing portions such as a
contingency reserve and increasing the portion borne by shareholders.
California is improving its pipeline safety with research and analysis as well. The Energy
Commission funded research to help address natural gas safety soon after the San Bruno
explosion and continues to award research funds for natural gas system projects on an
ongoing basis. Current research is focused on developing new technologies—such as
sensors and ultrasonic transducers—to monitor the integrity of gas pipelines. These projects
are intended to reduce the cost and size of leak detection sensors and diagnostic tools and
improve accuracy of leak and defect detection. The Energy Commission should continue to
support research that improves natural gas infrastructure and safety.
Infrastructure issues of another type are apparent in Southern California, especially in the
southern zone that includes the SDG&E gas service area and territory east to the
California/Arizona border receiving gas through Ehrenburg. This area is relatively isolated
with limited interconnection to other gas receipt points in California and no storage
facilities. This causes economic disincentives for both gas shippers (higher-priced markets
elsewhere) and end users (prices lower at other pipeline receipt points), even when there is
excess capacity. The CPUC has granted SoCalGas permission to enter the market and
purchase gas, assuming these are infrequent, small amounts of gas to meet total demand in
the southern system that is delivered to Ehrenburg. Unfortunately, a combination of
conditions led to a noncore customer curtailment watch on the June 30 and July 1, 2015 –
high gas demand when gas infrastructure was down for planned maintenance, coupled
with high temperatures causing high electricity demand when electricity supplies were
limited by lack of hydroelectricity and constraints on imports. This watch transformed into
an actual curtailment of natural gas service to certain power plants in the Los Angeles Basin,
causing the California Independent System Operator (California ISO) to issue a “Flex Alert.”
Localized curtailments or near-curtailments also occurred in the winter of 2013-2014 when
SoCalGas did not receive sufficient gas supply at Ehrenburg. Curtailments in the SDG&E
gas service area are of particular concern for two reasons. First, there is virtually no
industrial load in San Diego County, so there is little to curtail other than electric generation.
Second, much of the local area electricity generation was operating at higher levels to make
up for power generation lost with the closure of San Onofre Nuclear Generating Station.
In response to the event, SoCalGas filed an application 221 with the CPUC to modify the gas
curtailment rules, and asked the CPUC to approve the new rules by August 2016. The
220 D. 14-06-007, Findings of Fact 13 and 14. There apparently remains some dispute about whether
the cut-off date for ratepayers versus shareholders bearing pressure test costs is 1961 or 1956. See D.
15-03-049.
221 A-15-05-020
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changes reflect formal recognition that the gas and electric utilities and California ISO need
greater clarity and flexibility to work together to preserve electricity reliability when gas
reliability is threatened
With the problem occurring more frequently than anticipated, SoCalGas developed a more
comprehensive, physical solution to this “southern system minimum” problem by filing an
application with the CPUC to build a north-south pipeline. 222 The project would allow gas
received at northern receipt points to flow into the southern zone by adding a new 60-mile,
36-inch diameter pipeline.
The $621.3 million project is still pending at the CPUC. Interveners have proposed several
different alternatives that they claim could be constructed faster and lower cost. Evidentiary
hearings on the proposals were held in August, allowing CPUC action by the end of the
year.
The final infrastructure issue centers on increasing demand in Mexico for natural gas.
Mexican consumption increased by 4 percent per year in recent years, while its production
has grown by only 1.2 percent. Electricity generation is at the heart of this increased gas use,
as up to 24 GW of new natural gas combined-cycle power plants are expected to be added
by 2018. 223
Mexico produces its own natural gas, but it is uncertain whether the country can increase
the production at a pace that can match its growth in demand. Constitutional reforms
recently signed into law will allow foreign companies to share profits with Petróleos
Mexicanos and explore and drill for oil and gas in Mexico. 224 This could lead to higher
production in Mexico rather than relying on imports from the United States.
Mexico’s three liquefied natural gas (LNG) import terminals remain underused as LNG
commands higher prices in Asia than North America. This makes it more economic for
Mexico to pay for gas pipeline transportation from the United States pipelines east of
California than to import LNG from overseas. Delivering more gas to Mexico has meant
adding new pipeline capacity. Projects completed, proposed, or pending add up to more
222 A13-12-013, Application for Authority to Recover North-South Project Revenue Requirement in
Customer Rates and for Approval of Related Cost Allocation and Rate Design Proposals.
223 2014 Energy & Commodities Conference. Cadawalder, Wickersham & Taft, LLP. October 8, 2014.
http://www.energylawresourcecenter.com/blog/wp-content/uploads/2020/10/Panel-Five-Electric-
Market-Update-FERC-and-CFE1.pdf, p.20.
224 See, for example, http://rt.com/business/179824-mexico-signs-energy-reform-law/ or Diana
Villiers Negroponte, Mexico’s Energy Reforms Become Law, Brookings Institution, August 2014. Found
at http://www.brookings.edu/research/articles/2014/08/14-mexico-energy-law-negroponte.
171

than 7 billion cubic feet per day of new pipeline export capacity from the United States to
Mexico. 225
Most of these projects are located in South Texas and will export natural gas that could not
otherwise come to California. Several, however, notably the Sierrita Pipeline, Samalayuca
Lateral/Norte Crossing Pipelines, Willcox Lateral Expansion, Waha—San Elizario Pipeline
and Waha—Presidio/Ojinaga Pipeline, could siphon off gas that could otherwise compete to
serve load in California. These projects create additional competition for supplies that could
come to California. That impact could become more pronounced given that these new
export lines will receive their supply from the same line that interconnects with SoCalGas at
Ehrenberg to supply SoCalGas’ southern zone. Higher prices in markets east of California
could exacerbate the southern zone problems by further reducing the relative attractiveness
of the Ehrenberg receipt point.
Shale gas production in North America has resulted in a substantial increase in natural gas
supply, as well as a corresponding decrease in the price of natural gas. Because the 11 LNG
import terminals in the United States now sit mostly idle, producers are now seeking to sell
U.S. supply into export markets that pay higher prices than available here in the United
States.
This has led to several existing U.S. LNG import terminals filing applications with the U.S.
Department of Energy Office of Fossil Energy for authorization to export LNG under the
1938 Natural Gas Act. To date, five U.S. LNG export terminals have received export
authorizations, representing 9.2 billion cubic feet per day of export capacity. Only four have
commenced construction, and all are located on the Gulf or east coasts.
Natural Gas for Electric Generation
Several proposed or adopted federal air and water quality regulations are expected to
reduce the United States’ reliance on coal for generating electricity. These rules include the
air toxics rule, 226 the Clean Power Plan (111d), 227 the GHG new source performance
standard, 228 changes to water effluent rules, 229 and others. Together, they may increase
225 Canonica, Rocco, Ellen Nelson, Darrell Proctor, and Tricia Bulson. Growing Mexican Gas Market
Creates Southwest Price Premiums, Energy Market Fundamentals Report, Bentek Energy, Platts, May
2013; Sempra Energy Third Quarter 2014 Earnings Results, Nov. 4, 2014, p. 22,
http://files.shareholder.com/downloads/SRE/3699542155x0x791009/39C03F43-0449-4AE8-A8EA-
17BAD6F1AD7F/Q3-14_Presentation.pdf.
226 http://www.epa.gov/airquality/powerplanttoxics/.
227 http://www2.epa.gov/cleanpowerplan/clean-power-plan-existing-power-plants.
228 http://www2.epa.gov/cleanpowerplan/carbon-pollution-standards-new-modified-andreconstructed-power-plants.
229 http://water.epa.gov/scitech/wastetech/guide/index.cfm.
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demand for natural gas-fired generation, depending on what choices utilities make about
how to replace the electricity formerly generated by coal.
As California works to transform its energy system to dramatically reduce GHG emissions,
natural gas is expected to play an important, but smaller, role in the state’s energy mix in the
coming decades. 230 Roughly 40 percent of natural gas consumption in California is used to
generate electricity; for the United States, the amount of natural gas used for electric
generation is 31 percent. As California electric utilities convert electricity generation
portfolios away from carbon-intensive resources, the way natural gas is used will change.
These changes will affect not only the quantity of natural gas used to generate electricity,
but how and when natural gas-fired resources need to operate. These new operational
profiles will require a higher degree of coordination between the gas and electric industries
Keeping the gas system in balance could potentially become more challenging as the state
further increases the portion of the electricity generated from renewables. The electricity
produced from renewables such as wind and solar varies depending on conditions each
hour or even minute to minute. The California ISO and CPUC have been working to
identify the flexibility needs of California’s electricity system and its capability to ramp both
electricity production and demand up and down to keep the system in balance. Ongoing
efforts to increase the flexibility of the natural gas-generating fleet—as well as other
strategies to integrate renewables including through broader regional coordination—can be
expected as the state pursues a larger share of its electricity production from renewable
energy. 231 (See Chapter 2 and Chapter 9, Climate Impacts on Renewable Energy Generation and
Hydropower, for further discussion of efforts to integrate increasing amounts of renewable
energy.)
Combined Heat and Power Systems and Natural Gas
A CHP system produces a combination of useful thermal, electrical, and sometimes
mechanical energy through the use of waste heat from an electrical generator or preexisting,
thermally intensive process (such as manufacturing or industrial). In using heat that would
otherwise be wasted, a properly sized and operated CHP facility can produce energy using
less fuel than would normally be used to acquire the same energy via a more traditional
system of boilers and central-station grid electricity. While the cost-savings associated with
this increased fuel efficiency have historically been the primary incentive for installing CHP
systems, CHP can also provide secondary benefits for owners and operators, including
increased price certainty, energy security, control over business processes, and protection
from grid electricity outages. Furthermore, the state recognizes the potential for CHP to
230 The California Air Resources Board Climate Change Scoping Plan can be found at
http://www.arb.ca.gov/cc/scopingplan/resolution_14-16.pdf.
231 California Energy Commission, Tracking Progress, Resource Flexibility,
http://www.energy.ca.gov/renewables/tracking_progress/index.html, updated August 19, 2015.
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provide benefits beyond the needs of owners and operators, including decreased emissions
of GHGs and criteria pollutants, contribution to regional grid resource adequacy
requirements, reduced risk of major grid outages, reduction in net demand, reduction in
power transmission and distribution costs, and greater energy security for critical facilities.
In support of these benefits, the state has established several policies, programs, and
incentives to deploy CHP systems. The California Air Resources Board’s (ARB) Climate
Change Scoping Plan sets a target of an additional 4,000 megawatts (MW) of CHP capacity by
2020, which corresponds to a target reduction of 6.7 million metric tons carbon dioxide
equivalent (MMTCO2e) of GHG emissions. 232 Governor Edmund G. Brown Jr.’s 2010 Clean
Energy Jobs Plan calls for an additional 6,500 MW of new CHP capacity by 2030. 233
The value of CHP is also articulated in statute. Public Utilities Code Section (Pub. Util. Code
§) 372(a) states, “it is the policy of the state to encourage and support the development of
CHP as an efficient, environmentally beneficial, competitive energy resources that will
enhance the reliability of local generation supply, and promote local business growth.” This
objective was recognized in CPUC D. 10-12-035 that approved the Qualifying Facility (QF)
and CHP Program Settlement Agreement 234 (QF Settlement), which established a process
enabling existing CHP facilities to transition from a federal standard-offer contract model to
a state CHP program. CHP is also considered a preferred resource for meeting utility
resource needs. 235
The QF Settlement ended numerous legal disputes among investor-owned utilities (IOUs),
QF representatives, ratepayer advocacy groups, and the CPUC, and required that
California’s three largest IOUs procure 3,000 MW of CHP and achieve 4.8 MMTCO2e of the
2008 Climate Change Scoping Plan GHG reduction target—proportional to the amount of
electricity sales by the IOUs.
232 ARB, Climate Change Scoping Plan, Dec 2008,
http://www.arb.ca.gov/cc/scopingplan/document/adopted_scoping_plan.pdf, pp.33–34.
233 Office of the Governor, Clean Energy Jobs Plan, 2011,
http://gov.ca.gov/docs/Clean_Energy_Plan.pdf, p. 6.
234 CPUC, CHP Program Settlement Agreement (D.10-12-035), 2010,
http://docs.cpuc.ca.gov/word.pdf/FINAL_DECISION/128624.pdf, p. 2.
235 In 2003, the CPUC, Energy Commission, and California Power Authority adopted the Energy
Action Plan articulating a unified approach to meeting California’s electricity and natural gas needs. A
key element was the loading order, which specified California’s policy to invest first in energy
efficiency and demand response and then renewables and distributed generation before convention
generation. CHP, as a form of distributed generation, is given preferred resource status in the loading
order.
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On June 11, 2015, the CPUC issued Decision 15-06-028 236 establishing new procurement
targets for the QF Settlement’s Second Program Period. The decision also revised the GHG
Emissions Reduction Targets to collectively achieve 2.72 MMTCO2e of emissions reductions
from CHP facilities by 2020 and established a schedule for the IOUs to release four
competitive solicitations to achieve these targets from CHP facilities between 2015 and 2020.
Procurement Mechanisms and Incentives that Support CHP
The following programs and tariffs provide support to increase the economic viability of,
and encourage investment in, the development of CHP facilities in California:
• Assembly Bill 1613 (Blakeslee, Chapter 713, Statutes of 2007), the Waste Heat and
Carbon Emissions Reduction Act, established a feed-in tariff for CHP installations of
no more than 20 MW that meet specified fuel efficiency and emission standards. This
program has received little participation to date.
• The Self-Generation Incentive Program offers monetary incentives to encourage
customer adoption of eligible behind-the-meter, distributed generation technologies.
Though it began in 2001 as a peak-load reduction program, the program has since
shifted the primary focus to reducing GHG emissions. Eligible technologies include
(nonsolar) renewables, fuel cells, advanced energy storage, and CHP. By supporting
the deployment of highly efficient CHP, the Self-Generation Incentive Program helps
to ensure that natural gas is consumed in California as efficiently as possible. To that
end, program support for natural gas fueled technologies is limited to those that
achieve a net GHG emissions reduction. The CPUC has issued a proposed decision
that, if adopted, would reduce the allowable emissions rate of participating
technologies by 5 percent—from 379 kgCO2/MWh to 360 kgCO2/MWh.
• The CPUC recently issued a proposed decision that would adopt, with modification,
Southern California Gas Company’s (SoCalGas) application (A.14-08-007) to
establish a Distributed Energy Resources Services Tariff. The Distributed Energy
Resources Services Tariff would allow SoCalGas to design, install, own, operate, and
maintain advanced energy systems, including many forms of CHP, on or adjacent to
the customer’s premises. It is designed to help overcome barriers for potential
customers that might lack the internal capital and experience necessary to develop
and operate such facilities. If adopted, the Distributed Energy Resources Services
Tariff could help develop the largely untapped market potential of CHP facilities
with 20 MW or less in nameplate capacity.
236 CPUC Decision on Combined Heat and Power Procurement Matters, June 2015,
http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M152/K559/152559026.PDF.
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Role of CHP in Reducing GHG Emissions in the Future
Despite these many ambitious goals and policies, CHP growth and development in
California have been relatively flat in recent years and are likely to decline in the future.
When explaining this lack of progress, CHP developers and owners commonly cite
economic and regulatory barriers that result in a combination of cost and risk that is too
high to justify a project.
How CHP facility owners and developers respond to the new solicitations required by the
CPUC D. 15-06-028 remains to be seen. In the future, it is likely that some existing CHP
plants relying on power purchase contracts for export power will be unable to secure new
contracts and will shut down; however, it is unclear how much of the more than 4,000 MWs
of existing CHP facilities counted under the QF Settlement will close and install boilers in
the next 5 to 10 years. This is important to study and assess so that self-generation forecasts,
especially in the large industrial sector, can be adjusted to account for the closure of these
facilities.
Finally, evaluating the potential of small distributed CHP (less than 20 MW), as well as
emerging technologies and applications (for example, heating greenhouses and utilization
of CO2 for ripening produce) is important to understanding the potential environmental and
grid system benefits of CHP. According to the Combined Heat and Power: Policy Analysis and
Market Assessment, a study done by ICF International for the Energy Commission in 2012,
most technical potential for new CHP is in the 50kW to 5 MW range. 237 Exploring
renewable-fueled CHP and how it fits into the state’s renewable energy goals, looking at
applications for critical facilities, and soliciting new microgrid applications are all
opportunities that should be pursued and studied so clean, efficient, and reliable CHP can
continue to contribute to California’s energy and environmental goals.
Natural Gas as a Transportation Fuel
As discussed in detail in Chapter 6, the state has developed a portfolio of goals, policies, and
strategies designed to reduce GHG emissions, improve air quality, and reduce petroleum
use, while meeting transportation demands of the future. Transportation accounts for nearly
37 percent of California’s total energy consumption and roughly 37 percent of the state’s
GHG emissions. 238 While petroleum accounts for more than 90 percent of California’s
transportation energy sources, 239 there could be significant changes in the fuel mix by 2020
as a result of technology advances, market trends, consumer behavior, and government
237 Hedman, Bruce; Darrow, Ken; Wong, Eric; Hampson, Anne. ICF International, Inc.
2012. Combined Heat and Power: 2011‐2030 Market Assessment. California Energy
Commission.CEC‐200‐2012‐002. Table ES-1, p.4.
238 http://www.arb.ca.gov/cc/inventory/inventory.htm.
239 California Energy Commission, 2013 Integrated Energy Policy Report, 2013, p. 5.
http://www.energy.ca.gov/2013publications/CEC-100-2013-001/CEC-100-2013-001-CMF.pdf.
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policies. The range of alternatives to petroleum-based fuels is diverse—including biofuels,
electricity, hydrogen, and natural gas.
The 2014 IEPR Update discusses the role of natural gas as a transportation fuel in depth. It
points out that the Energy Commission has long considered natural gas as a near-term
bridging fuel to reduce carbon emissions — offering a modest carbon reduction from
petroleum fuels. In 2012, medium- and heavy-duty vehicles (such as long-haul trailers,
package delivery vans, shuttles, and buses) comprised about 3.7 percent of the California
vehicle population yet consumed more than 20 percent of the fuel. Medium- and heavyduty
vehicles are responsible for as much as 23 percent of transportation-related GHG
emissions and they also account for 30 percent of oxides of nitrogen emissions. Using lower
carbon-intensity fuels and advanced engine and pollution control technologies can help
reduce tailpipe pollution from medium- and heavy-duty vehicles. Using recently introduced
natural gas engines that achieve NOx emissions below the Optional Reduced NOx Emission
Standards of 0.02g/bhp, in combination with low-carbon biomethane fuel, provides an
opportunity to deploy vehicles that have significantly reduced NOx and GHG emissions.
These advanced natural gas vehicles are one potential option to help reduce criteria
pollutants in the San Joaquin Valley and South Coast Air Basins. (For more discussion, see
Chapter 9- Climate Change, Climate Change and Air Quality Considerations.) Natural gas
pathways are being explored in the truck and bus applications, as well as marine and rail
sectors.
Natural gas is also playing an important role in the development of the emerging hydrogen
vehicle industry. Natural gas use in vehicles accounts for about 1 percent of total
transportation fuel consumption. 240 There are several options available for producing
hydrogen fuel for transportation. A majority of existing hydrogen fueling stations use
hydrogen made by a steam reformation process that converts methane or natural gas to
hydrogen. This process could be used to allow hydrogen fueling stations and centralized
fuel producers to use the existing natural gas infrastructure as a secure source of fuel for
hydrogen production.
The Energy Commission’s Fuels and Transportation Division implements the Alternative
and Renewable Fuel and Vehicle Technology Program which provides up to $100 million
per year for projects that will transform California’s fuel and vehicle types to help attain the
state’s climate change and clean air policies. (For further discussion, see Chapter 4
Transportation, Alternative and Renewable Fuel and Vehicle Technology Program Benefits
Update.) To support natural gas-related activities in California’s transportation sector,
funding is targeted at the major areas where public investment can help remove barriers to
the adoption of this alternative fuel. In addition, the 2014 Integrated Energy Policy Report
240 Energy Commission, 2014 Integrated Energy Policy Report Update, p. 103.
http://www.energy.ca.gov/2014publications/CEC-100-2014-001/CEC-100-2014-001-CMF.pdf.
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Update 241 indicates that one key area showing improvement is transportation research. The
Energy Commission’s Energy Research and Development Division’s transportation research
program is focused on developing and advancing state-of-the-art electricity and natural gasfueled
transportation solutions that reduce fossil fuel consumption, GHG emissions, and air
pollutants in the state.
Many of California’s transit, municipal service, waste disposal, and freight transport fleets
have already converted their petroleum-consumption vehicle fleets to operate on natural
gas. Current natural gas vehicle options have a greater incremental cost compared to similar
gasoline or diesel vehicles. During times of high petroleum prices, this incremental cost can
be recouped through fuel savings, over a short period of time. With the significant drop in
petroleum prices since late-2014, the payback period needed to recoup this incremental cost
has increased significantly.
As discussed below in the section on GHG Emissions Associated With the Natural Gas System,
scientific understanding of the scale of methane emissions due to leakage throughout the
natural gas system—from extraction, processing, distribution and transmission, and at the
end use—is evolving. Because methane is the primary component of natural gas and a
potent GHG, continued engagement and research will be critical as the state continues to
initiate solutions to transform the transportation sector to reduce GHG and criteria pollutant
emissions. 242
End-Use Efficiency Applications and Natural Gas, Including Zero-Net Energy
Buildings
California households and businesses consume about one-third of the total state natural gas
demand, or about 7 billion therms of natural gas annually. 243 Residential natural gas
consumption is driven mostly by space and water heating, followed distantly by cooking
and miscellaneous residential uses, such as clothes dryers and pools. Similarly, commercial
natural gas consumption comes primarily from space and water heating, with cooking being
a significant end use as well. Other end uses in commercial buildings include process loads,
such as commercial laundry, heated pools, and other loads, such as paint dryers in auto
shops.
241 http://www.energy.ca.gov/2014publications/CEC-100-2014-001/CEC-100-2014-001-CMF.pdf.
242 Energy Commission. 2014 Integrated Energy Policy Report Update.
http://www.energy.ca.gov/2014publications/CEC-100-2014-001/CEC-100-2014-001-CMF.pdf, p. 4.
243 California Energy Commission. The Natural Gas Research, Development and Demonstration Program,
Proposed Program Plan and Funding Request for Fiscal Year 2012‐13, CEC‐500‐2012‐084, March 2012,
http://www.energy.ca.gov/2012publications/CEC‐500‐2012‐084/CEC‐500‐2012‐084.pdf, p. 17.
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Residential and commercial natural gas consumption has remained relatively flat for the
past two decades despite increases in population, jobs, and gross state product. 244 During
this period the California Building Energy Efficiency Standards have become increasingly
stringent, as have investments in statewide utility energy efficiency programs, contributing
to the relative flattening of natural gas consumption. The industrial sector is a major energy
consumer and one of the largest users of natural gas in the state, accounting for about 25
percent of total use in 2012. 245 The largest users include petroleum and coal products
manufacturing, oil and natural gas extraction, food processing, printing, and manufacture of
electronics, transportation equipment, fabricated metals, furniture, chemicals, plastics, and
machinery. These sectors represent prime areas of opportunity for reducing industrial
natural gas use. Consequently, industry represents an important target for improving the
efficiency of natural gas use through the adoption of new technologies and improved
energy management practices.
The passage of Senate Bill 350 (DeLeón, 2015) will further support energy efficiency
programs for natural gas end-uses. SB 350 requires the doubling of energy efficiency savings
by 2030, for electricity and natural gas combined. As with electricity, the CPUC will be
responsible for updating its policies on energy efficiency programs funded by ratepayers to
authorize a broader array of programs and tie incentive payments to measurable efficiency
results.
As the California Building Energy Efficiency Standards advance toward a goal of ZNE
buildings by 2020, there does not appear to be a clear-cut path for natural gas policy in enduse
applications when considering ZNE buildings. This issue is discussed in Chapter 1
under Issues Regarding Natural Gas Use in ZNE Buildings.
Low-Emission Resources and Biomethane
As part of his inaugural address, Governor Edmund G. Brown Jr. called for transitioning to
cleaner heating fuels to help achieve the state’s climate goals. Using eligible biomass to
produce renewable natural gas can be an important step in reducing GHG emissions from
the natural gas system. 246 The 2014 Integrated Energy Policy Report Update discussed
pathways to achieving a decarbonized natural gas supply chain that can serve
transportation, electricity, and direct end-use sectors.
244 Gross state product is a measurement of the economic output of a state or province. It is the sum of
value added by all industries within the state and is the state counterpart to national gross domestic
product.
245 California Energy Almanac available at: http://energyalmanac.ca.gov/naturalgas/overview.html.
246 Energy Commission RPS eligibility guidebook available at:
http://www.energy.ca.gov/2013publications/CEC-300-2013-005/CEC-300-2013-005-ED7-CMF.pdf
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Biomass sources such as residue from forest management practices, agricultural and food
processing wastes, organic human waste, and waste and emissions from water treatment
facilities, landfill gas, and other organic waste sources can be used to develop renewable
natural gas. Biogas is the raw, untreated gas generally produced from biomass and is
principally composed of methane and carbon dioxide. Biomethane is the treated product of
biogas where carbon dioxide and other contaminants are removed. Biomass is the biological
material used to create biogas. Biogas (or biomethane) can supplement or directly replace
the use of natural gas. In most cases, the potential for methane production is limited by
immutable factors, such as “waste-in-place” at a landfill or the volumetric flow of water into
a wastewater treatment plant. Production can be increased if there are opportunities to
process additional biomass feedstocks within normal agricultural or industrial operations,
such as diary digesters accepting food waste or wastewater treatment plants codigesting
fats, oils, and grease. Manure management, landfills, and wastewater treatment are three of
California’s largest anthropogenic methane-producing sources. Thus, the capture and
subsequent reduction of these methane emissions are arguably one of the greatest benefits
for using biomethane. This option may be limited, however, because of limited availability
of sustainable sources of biomass with very low net GHG emissions, as well as cost and
feasibility issues.
The 2014 IEPR Update provided a more detailed discussion of the potential role of
biomethane as a low-carbon transportation fuel. The Energy Commission provides
information to the U.S. Environmental Protection Agency so that low-carbon biofuels are
appropriately recognized and categorized in the annual Renewable Fuel Standard
volumetric targets.
The goal of Assembly Bill 1900 (Gatto, Chapter 602, Statutes of 2012) is to “promote the instate
production and distribution of biomethane” and to “facilitate the development of a
variety of sources of in-state biomethane.” A provision of the bill requires the CPUC to
adopt pipeline access rules that ensure that each gas corporation provides
nondiscriminatory open access to its gas pipeline system to any party for physically
interconnecting with the gas pipeline system and effectuating the delivery of gas. On
February 13, 2013, the CPUC opened Rulemaking 13-02-008, 247 which resulted in Decision
14-01-034 248 on January 16, 2014, and Decision 15-06-029 249 on June 11, 2015.
Decision 14-01-034 adopted standards that specify the concentrations of constituents of
concern that are found in biomethane, and monitoring, testing, reporting, and
recordkeeping protocols. Decision 15-06-029 concluded that the costs of complying with the
247 http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M050/K674/50674934.PDF.
248 http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M086/K466/86466318.PDF.
249 http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M152/K572/152572023.PDF.
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standards and protocols should be borne by the biomethane producers. To provide initial
support to the developing biomethane market, the decision adopted a policy and program
of a five-year monetary incentive program to encourage biomethane producers to design,
construct, and successfully operate biomethane projects that interconnect with the gas
utilities’ pipeline systems to inject biomethane that can be used at an end user’s home or
business. The support allows that each biomethane project that is built over the next five
years—or sooner if the program funds are exhausted before that period—can receive 50
percent of the project interconnection costs (up to $1.5 million) to help offset interconnection
costs.
Testimony received during the rulemaking estimated that the costs of interconnection can
vary and that the producer—even with the proposed support—may be required to expend
substantial interconnection costs. The Coalition for Renewable Natural Gas stated that
interconnection costs (for example, necessary studies, permitting, and/or equipment and
materials) could range from $1.5 million to $3 million, depending on the landfill location
(rural or urban) and the proximity of the project to the utility’s pipeline. For a point-ofreceipt
facility, Sempra estimates that the cost will depend on facility size and output and
that the costs could range from $1.2 million to $1.9 million. 250
GHG Emissions Associated With the Natural Gas System
Natural gas is composed of multiple chemical compounds, but methane is the main
component, comprising about 90 percent of the natural gas. Natural gas has the potential to
reduce GHG emissions by shifting away from higher carbon dioxide emitting fuels like coal,
gasoline, or diesel. Methane, however, is a highly potent, short-lived greenhouse gas that
can reduce or potentially eliminate the climate change benefits of switching to natural gas.
Methane emissions originate from the intentional operations of the natural gas system (for
example, venting of natural gas or pneumatic devices using natural gas) as well as from
leakage throughout the natural gas supply chain from the production, processing,
transportation, storage, distribution, and use of natural gas.
Estimating methane emissions from the natural gas system has proven challenging, with
divergence in estimates of methane emissions from recent research studies. Additional
research is underway at both the national and state level to reduce the uncertainty
surrounding current estimates. These efforts will help to provide California policy makers
with accurate and comprehensive assessments of life-cycle emissions from natural gas to
develop effective GHG reduction approaches.
The fundamental question regarding the climate benefits of using natural gas is how much
methane is escaping from the natural gas system. Researchers estimate emissions using
bottom-up, top-down, and hybrid methods. The bottom-up method is a straightforward
250 http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M152/K572/152572023.PDF, pp. 8-9.
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summing up of emissions using emissions factors for the various components of the natural
gas system. Top-down estimates use ambient measurements of methane and other
compounds in the atmosphere to estimate emissions. Hybrid methods try to take advantage
of both methods by reconciling the estimates from the top-down and bottom-up methods.
Methane emission estimates for California are uncertain. Recent work estimating methane
emissions from California’s natural gas system suggested emissions of less than one percent
of total throughput (or percent of production). 251 Some studies indicate these may be
underestimated. A comparison of various study results is complicated by the use of
different methodologies, data, and differences in the different components of the natural gas
system that are either excluded or included. This is an area of ongoing research.
The uncertainties and gaps in estimating methane emissions include:
• Most studies to date are not comprehensive life-cycle studies in that they typically do
not capture all of the components of the natural gas system such as emissions
downstream of the distribution system (for example, end use in homes) or from out-ofstate
natural gas production areas.
• Problems with measurement and sample bias may occur in the various studies because
sample sizes are not large enough—due to cost and practicality—to be statistically
representative of the population of various components of the natural gas system being
measured and extrapolated.
• The presence of superemitters that emit at significantly greater rates and volumes than
other similar types of emitters may be missed in sampling and, as a result, emissions
may be underestimated. Several studies suggest that methane emissions are dominated
by a small fraction of the emitters.
• Bottom-up and top-down estimates from oil and gas production in other states vary
widely and are complicated by the lack of accepted methods to allocate the emissions
between the natural gas and petroleum sectors, since many wells produce both oil and
natural gas.
Despite the uncertainty in the emission estimates, there is adequate evidence that California
needs to move forward aggressively to reduce methane emissions both inside and outside
the state. Ongoing research is underway to better understand emissions from the natural
gas system and identify actions to immediately reduce methane emissions. In addition,
natural gas utilities are already taking steps to reduce emissions. The following examples
highlight some of these activities:
251 Percent of production is a standard format for quantifying methane emissions; the other metric is
gigagrams of methane per year. Percent of production is measured by taking the amount of methane
emitted and dividing it by the total production of natural gas (or throughput) from the relevant area.
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• The Energy Commission is funding ongoing research to assess methane emissions and
support natural gas pipeline infrastructure and safety. This includes research to survey
the main sources of emissions such as production and processing, transmission and
distribution, underground storage units, abandoned wells, liquefied natural gas fueling
stations, and end uses in homes.
• The Energy Commission is also supporting studies on safety issues to be able to detect
leaks that may endanger public health and safety. For example, several ongoing projects
focus on developing and testing cost-effective leak detection and pipeline integrity
monitoring sensors and tools, as well as demonstrating them in the lab, under simulated
field conditions, and at a few actual field sites.
• California natural gas utilities are already taking actions to reduce methane emissions on
their distribution system, many of which are being driven primarily by safety concerns
following the San Bruno explosion. Investor-owned utilities have replaced old cast iron
pipelines, which are notorious sources of emissions, and have plans to accelerate
replacement of other pipes in their systems.
• Natural gas utilities are also actively engaged in research and development involving
the leak detection technologies and real-time notification of leaks. For example, PG&E is
using a mobile platform to detect leaks in the distribution system and to immediately
implement measures to eliminate these emissions. In another example, SoCalGas and
SDG&E are installing smart gas meters to help with detecting leaks.
• The ARB is developing a strategy to further reduce short-lived climate pollutants,
including methane, in accordance with Senate Bill 605 (Lara, Chapter 523, Statutes of
2014). In addition, the ARB has already developed regulations for methane from
municipal solid waste landfills and is in the process of developing regulations to reduce
methane from oil and gas production, processing, and storage operations.
• The ARB is also sponsoring several research efforts on methane including a study (to be
complete by the end of the year) to develop California-specific emission factors for
distribution pipelines. Additionally, the ARB continues to fund research taking
measurements of greenhouse gases at towers located throughout the state.
• The CPUC, working in partnership with the ARB, opened a rulemaking to reduce
emissions from natural gas transportation and distribution pipeline leaks pursuant to
Senate Bill 1371 (Leno, Chapter 525, Statutes of 2014). It requires the CPUC to establish
and requires the use of best practices for leak surveys, patrols, leaks survey technology,
leak prevention, and leak detection.
• The Environmental Defense Fund is coordinating a comprehensive study of methane
leakage with more than 100 academics, natural gas utilities, research institutions, and
others. The 16 projects include studies to measure and estimate methane emissions at
natural gas production sites, utility distribution systems, and other components of the
natural gas system. Ten of the studies have been completed, several others will be
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completed in the summer of 2015, and the synthesis project is expected in mid-to late-fall
2015.
• At the federal level, the Federal Energy Regulatory Commission has adopted a policy to
allow pipeline owners to recover major capital investment costs that address pipeline
safety or reduce GHG emissions. The U.S. Environmental Protection Agency has
proposed regulations to reduce methane emissions from compressors, well completions
and fracturing, and pneumatic devices.
• A number of federal agencies including the National Oceanic and Atmospheric
Administration, the U.S. Department of Energy, the National Aeronautics and Space
Administration, and others are actively engaged in research and development primarily
focused on development of methane sensors and developing better ways to identify
methane emissions.
The results of the research underway, including the Environmental Defense Fund research
effort, will be important in determining the role that natural gas should play in California
climate change strategies. In addition, new research and development is likely to be initiated
in the coming months to address the gaps and uncertainties identified above.
Natural Gas Outlook
Assessments of future natural gas demand, supply, prices, and infrastructure needs are a
critical part of the state’s efforts to ensure reliable supplies. These assessments also have
broader, cross cutting uses. For example, the price of natural gas is a key input into the
state’s Building Energy Efficiency Standards as it is used in the evaluation of the cost
effectiveness of proposed efficiency measures. (For more information about energy
efficiency, see Chapter 1.) These assessments are also a key input into the state’s electricity
forecast, as discussed in Chapter 5. Furthermore, the CPUC, other agencies, and some
utilities use these assessments for planning and decision-making. The Energy Commission’s
natural gas end-use assessments will need to evolve over time toward a similar level of
granularity as in the electricity forecast to support the provisions of Senate Bill 350 (De
León, 2015) that calls for doubling energy efficiency savings by 2030.
These assessments require an understanding of emerging issues and trends that could affect
natural gas markets and disruptions in supply. Factors that affect natural gas supply and
demand include production, population growth, pipeline capacity, the economic outlook,
weather, national and global markets, environmental concerns, and the effects of energy
policies. Supply and demand, in turn, affect natural gas prices.
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For the 2015 Natural Gas Outlook Report, staff developed natural gas market cases, or common
cases, 252 around trends that represent three possible future energy demand scenarios: a
business-as-usual or Mid Demand Case, a High Demand Case, and a Low Demand Case.
The Mid Demand Case represents a future in which the economy and commercial activity
remain consistent with trends experienced over the last several years. The High Demand
and Low Demand cases were created by altering assumptions in ways that would move
natural gas prices higher or lower, respectively, than in the Mid Demand Case. Varied
assumptions include economic growth, technology improvements, renewable portfolio
standards, coal-fired generation retirements, natural gas supply cost curves, demand, and
the production cost environment.
Natural Gas Prices
Figure 42 shows projected natural gas prices from 2015 to 2030. Prices were generated using
two sources; for 2015 to 2019 were produced using the natural gas futures prices as
published by the U.S. Energy Information Administration (EIA), while from 2020 to 2030
estimates were produced by the North American Market Gas Trade model (NAMGas). All
prices are for natural gas traded at Henry Hub, which is the North American benchmark
pricing point near Erath, Louisiana. These prices reflect the estimated cost of producing
natural gas, processing it for injection into the pipeline system, and transporting it to that
hub. The NAMGas model used in this analysis produces annual average estimates of
supply, demand, and price; therefore, they are annual averages, and do not account for
temperature-driven or other fluctuations that can occur in the natural gas market on a daily
or seasonal basis.
For the projections from 2015 to 2019, staff blended the NAMGas forecasts with the
September 14, 2015 trade date information from New York Mercantile Exchange web site in
the following manner:
• The 2015 and 2016 mid demand case values originated from the New York Mercantile
Exchange (NYMEX) futures strip.
• The 2017, 2018, and 2019 mid demand case values combined the NYMEX futures strip
and the NAMGas model projections. Staff averaged the NYMEX futures value and the
NAMGas model values to determine the 2017, 2018, and 2019 mid demand case
projections.
• Projections beyond 2019 originated from the NAMGas model.
In the high demand case, the model high price values were blended with the blended mid
demand case values from 2015-2019 to produce a reasonable slope to approach the
252 Staff refers to these cases as “common” because they are common to several analyses performed
for the 2015 Integrated Energy Policy Report across several Energy Commission offices.
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fundamentally higher price level for the high demand case. The low demand case uses
NAMGas results exclusively. Staff produced all values from 2020 forward within the
NAMGas model.
Figure 42: Common Case Natural Gas Price Results (Henry Hub Prices)
Source: California Energy Commission
Henry Hub prices exhibit annual growth rates between 3.5 percent and 5.6 percent per year
from 2015 to 2030 for the three cases. By 2030, prices in the low demand case reach $4.08
(2014$) per thousand cubic feet and prices in the high demand case reach $6.87 (2014$) per
thousand cubic feet. Between 2015 and 2020, prices in the mid demand case rise at an annual
rate of about 4.3 percent per year before settling into a more modest rate of about 2.2 percent
per year. From 2015 to 2020 the gas market reflects traders’ expectations of slowly rising gas
prices combined with fundamental market forces driving prices upward. In the United
States, natural gas demand in the power generation and industrial sectors is rising, and staff
expects prices to rebound from the lower than average prices experienced in 2015.
The majority of natural gas imported into California flows through two hubs, the Topock
pricing hub, located at the California-Arizona border, and the Malin pricing hub, located at
the California-Oregon border. The relative variations at the Topock and the Malin pricing
hub allow market participants to gauge the relative supply-demand balance in California.
Figure 43 shows the three price tracks (Malin, Topock, and Henry Hub).
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Figure 43: Prices at Malin, Topock, and Henry Hub
Source: California Energy Commission
While the patterns of price movements at the California pricing points parallel that of Henry
Hub, California’s gas sources and Henry Hub gas are physically separate and linked only by
the market influence Henry Hub has in the larger U.S. market. Figure 44 shows how Topock
exhibits a positive deviation relative to Henry Hub. The positive price differential reflects
relatively higher costs of resources produced in the San Juan basin region—known as the
Four Corners area and concentrated in northwest New Mexico into southwest Colorado—
and the added cost of transporting gas to the California border. Staff does not expect this
relative cost to change over the next decade. As a result, the differential remains positive
throughout the forecast horizon.
Figure 44: Prices Differentials (Point of Interest – Henry Hub)
Source: California Energy Commission
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The negative price differential at Malin reflects the fundamentally lower cost of gas
production both in the Rocky Mountain and Canadian regions and competition between
natural gas flowing south on Gas Transmission Northwest pipeline and natural gas flowing
west on the Ruby pipeline. The gas-on-gas competition between these two supply sources
results in California receiving a blend of these two low-cost sources. Both supply basins are
expected to continue producing at lower cost than gas traded at Henry Hub, resulting in the
negative differentials observed throughout the forecast horizon. Staff expects the differential
to grow in the coming years, driven by a widening gap between these low-cost traditional
basins and increasing cost of extracting gas from other parts of the country.
Natural Gas Production
The net effect of any price variation involves a combination of the two responses: consumers
can change the amount they purchase and suppliers can alter the amount they produce. The
NAMGas model uses more than 400 supply cost curves, each of which portrays a
relationship between the marginal cost of the next unit of natural gas and the amount of
natural gas available. As a result, each curve competes with the other curves to satisfy the
determined demand. Figure 45 shows U.S. production by resource type, along with the
relative share each type occupies in the supply portfolio. The prominence of shale gas
production has dramatically altered and will continue to reconfigure, the supply portfolio
between 2010 and 2020.
Figure 45: Historical and Projected Natural Gas Production by Resource Type in the
United States
Source: Derived from PointLogic Energy Database
Natural Gas Demand
As part of each IEPR cycle, staff forecasts end-user natural gas demand for California with a
suite of end-use and econometric models structured along utility planning area boundaries.
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The demand forecast results include projections for fuel use in the residential, industrial,
commercial, agricultural, and transportation, communications, and utilities demand sectors.
The estimates produced by the end-use demand forecast models are then used as inputs to
the NAMGas model for California and combined with estimates of price responsiveness for
areas outside California to produce demand estimates covering all of North America in the
Mid Demand Case. The High Demand and Low Demand Cases used a similar process that
pushes demand either above or below the Mid Demand Case, respectively, while
maintaining consistency with the other Energy Commission models.
Natural gas demand in California is shown in Table 11.
Table 11: Statewide Baseline End-Use Natural Gas Forecast Comparison
Demand (Million Therms)
2013 CED End-
Use Natural
Gas, Mid
Demand
2015 End-Use
Natural Gas,
High Demand
2015 End-Use
Natural Gas,
Mid Demand
2015 End-Use
Natural Gas,
Low Demand
1990 12,892
12,892 12,892 12,892
2000 13,913 13,913 13,913 13,913
2013 12,515
13,240 13,240 13,240
2015 12,675
13,565 13,438 13,364
2020 12,728
14,195 13,711 13,742
2024 12,736 14,851 14,185 14,352
Average Annual Growth Rates
1990-2000 0.76% 0.72% 0.72% 0.72%
2000-2012 -0.71% -0.70% -0.70% -0.70%
2012-2015
-0.21% 1.81% 1.56% 1.41%
2012-2022 0.04% 1.32% 0.93% 1.01%
2012-2024 0.03% 1.34% 0.93% 1.04%
Historical values are shaded.
Source: Energy Commission staff
The new forecasts begin at a higher point in 2015, as actual natural gas consumption in
California was higher in 2015 than forecasted in the CED 2013 mid case. Staff attributes this
to an expected steep increase in forecasted prices that did not materialize. The new forecasts
grow at a higher rate in all three cases from 2012 – 2024. Staff attributes the higher growth
rates to an increase in natural gas demand for transportation (light-duty vehicles, buses,
medium and heavy-duty trucks, with heavy-duty trucks having a large increase over the
forecast period), followed by an increase in residential demand. The mid cases also include
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potential climate changes in the forecasts, while the high and low cases do not, this results
in mid cases demand being lower than the low case in some instances. Staff projects by 2024,
demand in the 2015 preliminary end-use natural gas demand mid case to be around 11
percent higher compared to the CED 2013 mid case.
Natural gas demand for power generation was estimated using electricity production cost
modeling for electric generation in the Western Electricity Coordinating Council (WECC)
area, which includes California. These natural gas demand projections were used as fixed
values in the NAMGas model in a similar fashion to the way natural gas end-use demand
was used. Natural gas demand for power generation for areas outside the WECC were
estimated using the NAMGas model. Figure 46 shows the estimated gas demand for power
generation inside California produced in the production cost model.
Figure 46: Natural Gas Burn for Power Generation in California (000s MMBtu)
1,200,000
1,000,000
800,000
600,000
400,000
Mid
Low
High
200,000
-
Source: Energy Commission
In all three cases, natural gas demand for power generation falls over the forecast period.
This is driven by increases in alternative generation sources such as renewable energy that
reduces the need for power from fossil-fueled sources. Figure 47 shows the breakdown of
generation sources by type for the mid cases.
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Figure 47: Mid Demand Case Generation Fuel Sources 2015-2026
275000
250000
225000
200000
GWh
175000
150000
125000
100000
Wind
Solar
Geothermal
Biomass
AAEE
Gas
Coal
Nuclear
Hydro
75000
50000
25000
0
2015 2016 2017 2018 2019 2020 2021 2022 2023 2024 2025 2026
Source: Energy Commission
Recommendations
• Continue to monitor changes in the natural gas and electricity generation
interface. As the use of natural gas for power generation increases nationwide and
the need for quick ramping gas-fired generation to integrate intermittent renewable
resources has grown, natural gas and electricity industries have become increasingly
interdependent. To ensure continuity of both wholesale and retail supply as
wholesale reliance on natural gas increases, there is need for better coordination of
pipeline delivery of natural gas with electric system reliability needs, particularly in
the San Diego region. Monitor SoCalGas proposals at the CPUC to either increase
gas deliveries to Ehrenberg or build new infrastructure to connect its northern and
southern pipeline systems.
• Provide information to the U.S. Environmental Protection Agency. Provide
information so that low-carbon biofuels are appropriately recognized and
categorized in the annual Renewable Fuel Standard volumetric targets. The 2014
IEPR Update points to biogas being injected into natural gas pipelines as a way to
help ensure that biogas can be safely and economically used in the state. The Energy
Commission should work with the CPUC and the ARB to overcome potential
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arriers impeding commercial biogas projects and explore the availability of
potential funding or incentive programs to help bring additional low-carbon biogas
projects on-line.
• Use ongoing research to better understand the societal benefits of natural gas as a
transportation fuel and apply to policy decisions. Research and investigations into
the impact of methane leakage on the environment are ongoing. Initial reports have
shown that methane leakage may have a larger impact on the environment than
originally estimated. Due to the intricacies of regional natural gas systems and the
scale of possible leakage points that need to be monitored, continuing research on
this topic will be necessary to clarify and refine environmental impact estimates.
Information gathered from these efforts should be integrated into decisions on the
best mix of technologies California should use to achieve our transportation sector
emissions reduction goals.
• Monitor economic impacts on the adoption rate of advanced natural gas vehicles.
California has been a leader in not only supporting the advancement of cleaner
transportation options but also supports the accelerated deployment of those
technologies. One of the major driving factors that determine the rate of turnover for
older more polluting vehicles is the costs of transitioning to those cleaner
technologies. The Energy Commission should continue to closely monitor the
economic conditions surrounding the replacement of the aging gasoline and diesel
fleet advanced natural gas engines. This information will be essential to determining
the cost-benefit ratio for possible investments in this sector.
• Analyze the cost and benefits of CHP and on exporting CHP. Continue to develop
and support new frameworks that will better value the true costs and benefits of
combined heat and power generation and align utility incentives with those costs
and benefits. The Energy Commission recognizes that new regulatory and market
frameworks could lessen the challenges facing combined heat and power today.
Also, the Energy Commission should evaluate the effects of the CPUC decision on
exporting CHP.
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CHAPTER 7:
Updates From the 2013 Integrated Energy Policy
Report (IEPR) and the 2014 IEPR Update
This chapter provides updates on three topics discussed in the 2013 Integrated Energy Policy
Report (IEPR) and the 2014 IEPR Update: electricity infrastructure in Southern California,
changing trends in California’s sources of crude oil, and progress in implementing 2013 IEPR
recommendations for San Onofre Nuclear Generating Station (San Onofre) and Diablo
Canyon Nuclear Power Plant.
Electricity Infrastructure in Southern California
Background
Ensuring reliability of the electricity system in southern California has been a major focus
for the last several years primarily due to the impending retirement of several fossilpowered
facilities and the closure of the San Onofre as well as other causes. Southern
California, principally customers of San Diego Gas & Electric (SDG&E), has suffered outages
that create inconvenience, discomfort and economic harm. 253 This issue has been included
each year in the IEPR since 2011.
The retirement of fossil-powered facilities stems from a policy to better protect coastal
waters. In May, 2010, the State Water Resources Control Board (SWRCB) approved a policy
to phase out the use of once-through cooling (OTC) in California power plants. 254 The OTC
policy establishes uniform, technology-based standards to implement federal Clean Water
Act section 316(b) at coastal power plants with the goal of reducing harmful effects
associated with cooling water intake structures on marine and estuarine life. 255 The policy
included many grid reliability recommendations and an implementation proposal
developed jointly by the Energy Commission, the California Public Utilities Commission
(CPUC), and the California Independent System Operator (California ISO). The policy
253 The SDG&E area suffered a major outage (1.4 million customers) on September 8, 2011, lasting
about twelve hours. SDG&E suffered a smaller scale outage (100,000 customers) on September 20,
2015, lasting two hours. In the 2015 outage, the California Independent System Operator ordered
SDG&E to shed 150 MW of load to assure system integrity and to avoid a large, uncontrolled
collapse. Participants in Southern California Edison’s demand response programs were called upon
several times in 2015 to prevent overall system problems.
254 Once-through cooling is a form of power plant turbine condenser cooling technology that pumps
water from a natural source (such as the ocean), through a steam turbine condenser, and then returns
it back to its source. On May 4, 2010, the State Water Resources Control Board approved an OTC
policy that required the phase out of these technologies.
255 http://www.swrcb.ca.gov/water_issues/programs/ocean/cwa316/rcnfpp/index.shtml.
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ecame regulation in October 2010, affecting 19 California power plants. Of those, 10 power
plants totaling about 11,026 megawatts (MW) are in the Los Angeles and San Diego Basin.
Of these, seven facilities are in the California ISO balancing authority area, and three are in
the Los Angeles Department of Water & Power (LADWP) balancing area. 256
San Onofre has turned out to be especially critical to reliability in Southern California
because it predated much of the growth in the region and the transmission system was
planned under the assumption that it would always be operational. Although now retired,
San Onofre was a 2,200 MW facility that had provided about 9 percent of California’s
electricity generation and other important reliability services to the grid. Following the
initial January 2012 shutdown of San Onofre, the California ISO’s summer 2012 operational
reliability assessments revealed voltage collapse consequences that had not previously been
studied. Mitigation actions were taken to address these concerns. Shortly following
Southern California Edison’s (SCE) June 2013 announcement that it would retire San Onofre
rather than repair the damaged steam generators, Governor Brown asked the energy
agencies, utilities, and air districts to draft a plan for replacement of the power and energy
that had been provided by San Onofre. This effort resulted in the Preliminary Reliability Plan
for LA Basin and San Diego, prepared jointly by technical staff of energy agencies, air districts,
the ARB, and utilities. This report was presented in the 2013 IEPR. 257
The preliminary plan sought to identify actions state and local agencies can take to maintain
reliability in the Los Angeles and San Diego region, based on the California ISO’s estimates
of local capacity requirements. The plan put forward a rough replacement target of 50
percent preferred resources (energy efficiency, demand response, fuel cells, renewable
distributed generation, combined heat and power, and so forth) and 50 percent conventional
generation. The plan also raised the need to authorize transmission upgrades to reduce local
capacity requirements. Lastly, the plan called for establishing contingency plans in the event
resources fail to materialize. While the document was not finalized by the executive
management of participating energy agencies at that time, an interagency team (known as
the Southern California Reliability Project, or SCRP 258 ) has continued to meet regularly since
the fall of 2013. SCRP members presented on their progress at an August 2014 IEPR Update
workshop in Los Angeles and most recently at an IEPR workshop on August 17, 2015, in
Irvine.
256 California Energy Commission. Tracking Progress, Once-Through Cooling, updated February 17,
2015. http://www.energy.ca.gov/renewables/tracking_progress/index.html#otc.
257 Preliminary Reliability Plan for LA Basin and San Diego, August 30, 2013.
http://www.energy.ca.gov/2013_energypolicy/documents/2013-09-09_workshop/2013-08-
30_prelim_plan.pdf.
258 SCRP member agencies are the Energy Commission, the CPUC, the California ISO and the ARB.
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Local Capacity Area Requirements
Ensuring sufficient resources in local capacity areas is a key component of ensuring reliability
in the Southern California region. Local capacity areas are transmission-constrained areas,
which are identified when the maximum combined import capacity across the set of
transmission line segments between pairs of substations defining a region is less than the
peak load within the region. To serve load reliably, each local capacity area must have
enough generation located within the local area to meet peak load, less the maximum
import capacity of the transmission lines connecting that area to the high-voltage
transmission system. Local capacity requirements (LCR) refer to the amount of generating
capacity required within the local area. Upon the 2007 implementation of a resource
adequacy program by the CPUC and California ISO—with support from the Energy
Commission—local capacity areas and LCRs became a more visibly important part of
electricity reliability planning. 259
The California ISO began preparing annual assessments for each of 10 load pockets for 1-
and 5-year forward time horizons beginning in 2006. One-year-ahead studies provide the
basis of local resource adequacy requirements that each load-serving entity must satisfy by
obtaining net qualifying capacity to meet its peak load ratio share of total LCR requirement
in the load pocket. The 5-year-ahead study results also provide useful information to inform
generation planning and procurement. Beginning in 2010, the California ISO began
conducting 10-year-ahead LCR studies as part of its support for the Assembly Bill 1318
project. 260 Ten- year-ahead studies were also performed for the CPUC in its 2012 Long Term
Procurement Plan (LTPP)–Track 4 proceeding and have become an important part of the
California ISO’s annual transmission planning process.
Given how involved and labor-intensive the power flow modeling techniques used in LCR
studies can be, California ISO staff analysis is limited to a small number of specific cases
with alternative sets of assumptions.
Aging Natural Gas Fleet in Southern California
Southern California relies upon a large number of old, natural gas-fired steam boiler
facilities that have long outlived the original design life and purpose. Much of this capacity
is located along the coast line to use OTC technologies. Motivated to reduce criteria air
pollutant emissions, South Coast Air Quality Management District (SCAQMD) adopted an
incentive for owners to replace such steam boiler generating units with advanced gas
259 CPUC, Rulemaking 05-12-013, D.06-06-064,
http://docs.cpuc.ca.gov/PublishedDocs/WORD_PDF/FINAL_DECISION/57644.PDF.
260 Assembly Bill 1318 (Wright, Chapter 206, Statutes of 2009) requires the California Air Resources
Board in consultation with the Energy Commission, CPUC, California ISO, and the State Water
Resources Control Board, to prepare a report for the Governor and Legislature that evaluates the
electrical system reliability needs of the South Coast Air Basin.
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turbine technology. 261 The Energy Commission adopted a recommendation urging the
CPUC to authorize replacement capacity for aging power plants in the 2003 IEPR. After
studying the issue for several years, in May 2010, the SWRCB adopted its OTC policy to
phase out the use of this technology and established December 31, 2020, as the compliance
date for most facilities still using once-through cooling. 262
In its 2012 and 2014 Long-Term Procurement Plan rulemakings, the CPUC examined the
need for resources to replace OTC facilities and
Key Power Engineering Terms
San Onofre. The CPUC authorized SCE and
SDG&E to procure a combination of preferred Reactive power is a byproduct of alternating
current (AC) systems when voltage and current
resources and conventional gas fired generation.
are not in phase. It is produced when the
As a result, SDG&E proposed and the CPUC has current leads voltage and consumed when the
approved development of a gas-fired peaking current lags voltage. Reactive power (vars) is
required to maintain the voltage to deliver
facility at Carlsbad to replace Encina, a 946 MW
active power (watts) through transmission
OTC facility. SCE submitted a package of preferred lines. Several devices (rated in MVars) can be
resource contracts and proposed power purchase used to control reactive power in addition to
agreements for new generation in November 2014. traditional generating facilities.
The CPUC is nearing the end of its review with no
decision at this time.
The retirement of San Onofre revealed the extent
to which the entire Los Angeles Basin/San Diego
region was vulnerable to low-voltage and
posttransient voltage instability concerns (voltage
stability problems in the time period beyond the
initial contingencies). 263 Importantly, the results of
technical studies shifted from localized thermal
overload concerns into regionwide, low-voltage
and posttransient voltage instability issues. The
California ISO strategy has been to replace reactive
power that was supplied from San Onofre with
Shunt capacitors—mechanically switched or
fixed capacitor banks installed at substations or
near loads that control voltage by charging and
discharging capacitors
Static VAR compensators—combine
capacitors and inductors with fast switching
time frame capability
Synchronous condensors—synchronous
machines are designed exclusively to provide
continuously variable reactive power support
Source: Oak Ridge National Laboratory,
http://web.ornl.gov/sci/decc/RP%20Definitions/
Reactive%20Power%20Overview_jpeg.pdf
nongeneration electrical components (shunt capacitors, static VAR compensators,
synchronous condensers, and so forth) that can control voltage. 264 (See sidebar for
261 SCAQMD Rule 1304(a)(2) allows an exemption from the provision of offsets for an advanced gas
turbine project by retiring existing steam boiler capacity on a megawatt for megawatt basis.
262 http://www.waterboards.ca.gov/water_issues/programs/ocean/cwa316/policy.shtml
263 Addendum-2013LCTA Report, http://www.caiso.com/Documents/Addendum-
Final2013LocalCapacityTechnicalStudyReportAug20_2012.pdf.
264 Control of the electrical grid using reactive power maintains the necessary balance among the
phases of alternating current systems. However, reactive power devices do not generate real power
196

definitions.) The California ISO approved such projects in its annual transmission planning
process. Installation of these kinds of transmission elements has reduced the amount of new
generating capacity that needs to be located close to load and thus increased the flexibility in
locating replacement resources. Some local capacity is still required, however, due to the
limitations of the existing transmission system.
Current Interagency Collaboration to Ensure Reliability in Southern California
Normal mechanisms are underway at the energy agencies to review and approve a mixture
of preferred resources, 265 conventional generating capacity additions, and transmission
system upgrades. The CPUC is overseeing the IOUs’ implementation of D.14-03-004, 266
directing SCE and SDG&E to target preferred resource development and new generation in
desired locations. The Energy Commission is processing permits for a variety of proposed
generation projects, some of which may be built if the CPUC approves a power purchase
agreement (PPA). 267 The California ISO is studying, and in some cases authorizing,
transmission system upgrades that address the voltage instability concerns created by the
retirement of San Onofre. The IOUs, and in some cases independent transmission
developers, are designing, building, and operating the transmission projects authorized by
the California ISO.
The SCRP agencies frequently communicate about the development of these numerous
resources and are closely following the schedules put forward by project developers.
In its 2014-2015 Transmission Plan, 268 the California ISO restudied local capacity
requirements in Southern California. In its assessment of local capacity issues for 2024, the
California ISO found that the combined L.A. Basin/San Diego region would be slightly
deficient if SCE and SDG&E pursued only the projects submitted to the CPUC for approval
or energy; thus, actual resources (either preferred or conventional) needed to supply load must be
developed to replace the generating capacity and energy provided by San Onofre and the fossil OTC
facilities.
265 Preferred resources include energy efficiency, demand response, fuel cells, renewable distributed
generation, combined heat and power, and so forth.
266 CPUC. Decision Authorizing Long-Term Procurement for Local Capacity Requirements Due To
Permanent Retirement Of The San Onofre Nuclear Generations Stations. Decision14-03-004, issued March
14, 2014. http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M089/K008/89008104.PDF.
267 http://www.energy.ca.gov/sitingcases/alphabetical.html.
268 http://www.caiso.com/planning/Pages/TransmissionPlanning/2014-
2015TransmissionPlanningProcess.aspx.
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as of late 2014 and identified repurposing 269 demand response as a potential mitigation
measure. 270
Local Capacity Needs in Southern California
Concerned about the California ISO findings of insufficient resources in 2024, Energy
Commission staff developed a local capacity annual assessment tool to supplement the
California ISO’s analysis of local capacity requirements. 271 In the tool, the Energy
Commission staff use the assumptions from the CPUC’s 2014 LTPP rulemaking and the
California ISO’s 2014-2015 Transmission Plan for its baseline inputs. The analysis provides
year-by-year projections of resource surpluses or deficits relative to local capacity
requirements for five areas within Southern California. This tool is capable of quickly
assessing the consequences of many combinations of input assumptions. In comparison, the
California ISO’s analysis uses power flow studies that are highly resource intensive, thus
limiting the number of variations that can be assessed with the staffing levels and time
constraints of the annual transmission planning process.
The Energy Commission staff analyses using baseline assumptions show deficits in the
combined Los Angeles Basin/San Diego area, the Los Angeles Basin local capacity area, and
the West Los Angeles subarea beginning in 2021 and extending through 2024. Although
transmission system upgrades and demand-side savings reduce local capacity requirements
from what they otherwise would have been, the expected decline of resources due to OTC
retirements at the end of 2020 results in deficits by 2021. The pattern of near-term surplus
and longer-term deficit is common to all three regions, but it is more pronounced for the Los
Angeles Basin than for the combined Los Angeles Basin/San Diego area because the OTC
facilities retired in 2021 are all located in the Los Angeles Basin. The deficit is greatest as a
proportion of load in the West Los Angeles subarea, because all of the OTC facilities retired
are located in the West Los Angeles subarea. Figure 48 shows this general pattern for the
Los Angeles Basin.
269 The California ISO uses the term repurposed to describe demand response that has sufficient
operational characteristics to be used by the California ISO to meet contingency conditions (for
example, demand response that is available within 20 minutes of notification that it is needed).
270 California ISO. 2014-15 Transmission Plan, pp. 147-150.
271 California Energy Commission, Assessing Local Reliability In Southern California Using A Local
Capacity Annual Assessment Tool, CEC-200-2015-004, August 2015,
http://www.energy.ca.gov/publications/displayOneReport.php?pubNum=CEC-200-2015-004.
198

Figure 48: Baseline Projections Showing Local Capacity Surpluses/Deficits for the Los
Angeles Basin Local Capacity Area
Source: Energy Commission staff, 2015
There is uncertainty surrounding the assumptions used in the baseline assessment;
therefore, staff conducted both a sensitivity study for the effect of individual variables and a
scenario study changing assumptions for multiple variables in logical groupings. Staff
developed four alternative scenarios, including an optimistic and pessimistic scenario
designed as “bookend” cases unlikely to be encountered. The other two scenarios involve
fewer departures from baseline and are more likely to reflect the expected range of
outcomes. Figure 49 plots the supply versus requirements surplus/deficit for the baseline
and four alternative scenarios for the Los Angeles Basin area. Each of the four alternative
scenarios shows the same basic pattern as the baseline results, for example, substantial local
capacity surplus through 2020 and a major decline in local capacity for 2021 due to OTC
retirements. The two more pessimistic scenarios have deeper deficits that are not overcome
through the end of the analysis period. Even the moderately optimistic scenario has a very
small single-year deficit in 2021. The optimistic scenario shows surpluses for all years.
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Figure 49: Baseline and Alternative Scenario Results Showing Local Capacity
Surpluses/Deficits for the Los Angeles Basin Local Capacity Area
Source: Energy Commission staff, 2015
Contingency Planning if Development of Preferred Resources, Conventional
Generation, and Transmission do not Advance as Planned
If all preferred resources, conventional generation, and transmission resource development
continues as planned, reliability in Southern California would likely be assured within a
small tolerance that can be met with minor changes in programs or fully using procurement
authority that the IOUs have not yet exercised. 272 Because resource margins are tight in
Southern California, however, maintaining reliability requires closely coordinating the fossil
OTC retirement and resource development in the right locations to satisfy local capacity
requirements.
A new undertaking of the SCRP is tracking preferred resource development and sharing the
data among the energy agencies. The SCRP is tracking both conventional programs and
additional preferred resource development that was ordered in D.14-03-004 and assumed in
California ISO power flow modeling studies to establish local capacity requirements. The
CPUC is providing quarterly updates to document both preferred and conventional
resource development. Similarly, the California ISO is providing frequent updates about the
transmission upgrade projects that are relied upon to reduce local capacity requirements.
For its part, the Energy Commission is sharing information on the progress that specific
272 SCE has not yet satisfied the minimum preferred resource requirement of D.14-03-004 and has
additional capacity authorization it may pursue at its discretion.
200

generating projects are making in the permitting process. These monitoring mechanisms
enable the agencies to continuously be aware of expectations for all pertinent resource
development.
Over the past year, the SCRP team has worked to develop contingency mitigation measures
that can be triggered if resource expectations do not match requirements. Two concepts
were introduced at the 2014 IEPR Update workshop:
• A request to the SWRCB to defer compliance dates for specific OTC facilities whose
retirement is linked to a specific new power plant that would replace it.
• Developing conventional power plant proposals as far through the permitting and
procurement processes as practicable, but then holding the projects in reserve to
receive final approval and begin construction only if triggered by expected reliability
problems.
The details of each of these two types of mitigation measures have been refined over the
past year.
OTC Compliance Date Deferral
Efforts to develop the OTC compliance date deferral measure are now essentially complete.
The sequence of steps has been discussed among the SCRP team and with the SWRCB staff.
Five broad steps would be followed in sequence:
• Conducting analyses and preparing a draft request to Statewide Advisory
Committee on Cooling Water Intake Structures (SACCWIS) 273 ready for public
comment
• Issuing the draft request for comments, responding to comments, revising requests,
and conducting a publicly noticed SACCWIS meeting
• SWRCB review of SACCWIS report and preparation of the staff recommendation
• Public notice, comment, comment response, board consideration
• Preparation of Office of Administrative Law package and review by the Office of
Administrative Law
Allowing normal periods for each of the above steps to enable a full public process would
take roughly one year, although this could be accelerated if unforeseen circumstances
warranted it, or it might take longer if the energy agencies believed new analyses were
necessary to substantiate the need for deferral.
273 SACCWIS includes seven organizations: California ISO, Energy Commission, CPUC, California
Coastal Commission, State Lands Commission, California Air Resources Board (ARB), and SWRCB.
201

New Gas-Fired Generation Development
Energy Commission staff, with input from technical staff of the other SCRP agencies,
developed a paper outlining three options for a new generation mitigation measure. 274 These
were:
• Option 1: Utility issues a request for offers to elicit project proposals from developers
• Option 2: Utility develops a project and takes it through the permitting process and
then turns it over to developers once triggered
• Option 3: Rely exclusively on a pool of projects that are already permitted but do not
have PPAs
Each of the options can be thought of as having two stages. Stage 1 is to develop a specific
power plant project proposal and to move it through the permitting process at the Energy
Commission and the procurement approval process at the CPUC to the point that most
issues are resolved, and then for the project to essentially “sit on the shelf.” If circumstances
warrant triggering the project, then the permitting and procurement efforts would be
completed and the project would be constructed and become operational. The first two
options essentially start from scratch to begin the development of new facilities and would
take a lengthy period to complete stage 1. Option 3 takes advantage of an expected pool of
projects likely to receive Energy Commission permits and could “sit on the shelf” for a few
years waiting to be triggered if contingencies warrant construction.
Each of the options has advantages and disadvantages. Projects designed under Options 1
and 2 could be located to address specific problems that transmission reliability assessments
would reveal, for example, thermal overloads on specific transmission line segments,
voltage stability issues in specific regions, and so forth. Only Option 3 would provide a
mitigation measure that could actually be constructed and become operational by summer
2021. Options 1 and 2 would incur expenses from project design, site acquisition, and the
permitting and procurement processes that would need to be recovered in some manner.
Similar expenses under Option 3 have been made by developers going through the process
to design and permit projects that have not been selected by a utility for a PPA or approved
by the CPUC. 275 Since air quality agencies have made clear that permits will become stale
274 Jaske, Michael and Lana Wang. 2015. Gas-Fired Generating Plant as Mitigation for Contingencies
Threatening Southern California Electric Reliability. California Energy Commission, Energy Assessments
Division, CEC-200-2015-005. http://docketpublic.energy.ca.gov/PublicDocuments/15-IEPR-
07/TN205700_20150812T141329_GasFired_Generating_Plant_as_Mitigation_for_Contingencies_Threa
.pdf.
275 If such a project is eventually constructed, the development costs would be recovered through the
financial arrangements of the PPA. If never developed, then these expenses would be written off by
the developer and/or investors.
202

and need to be updated, creating further expenses for speculative projects that one hopes
will never be constructed, it is unclear how long a pool of projects will persist to make this
approach viable beyond the next few years.
Triggering the Mitigation Measures
The contingency process discussed among the SCRP agencies seeks to assure reliability by
anticipating any projected shortfall of resources needed to meet local capacity requirements.
To accomplish this requires creation of an analytic process for the early detection of such
shortfalls. As described above, Energy Commission staff has developed a local capacity
projection tool that builds off California ISO power flow study results for snapshot years to
provide a year-by-year accounting for resource surpluses or deficits compared to local
capacity requirements. A protocol would be developed to determine whether any projected
shortfalls revealed by this tool justifies a recommendation to trigger mitigation measures.
The California ISO would be asked to conduct confirmatory power flow studies to verify the
conclusions of the projection tool in some instances. If the leadership from the energy
agencies recommends triggering mitigation measures, then the applicable agencies
overseeing a specific mitigation measure approval would implement proposed actions
according to approval processes established in advance.
Other Mitigation Options
The contingency mitigation options are designed for a failure of a gas-fired resource
addition, a substantial shortfall in the collective impacts of preferred resources, or inability
to bring the transmission system upgrades on-line. Such options need to be capable of
providing effective capacity with a short lead-time. It is not clear whether preferred
resources that build up slowly through voluntary participation by end users can readily
satisfy this requirement. Very aggressive levels of energy efficiency are already being
assumed through additional achievable energy efficiency projections (discussed further in
Chapter 5 on the Electricity Demand Forecast); it may not be feasible or sensible to design
further programs with savings that are extremely predictable and then implemented only
when a contingency warrants. If such savings can be identified that are cost-effective,
feasible, and achievable with existing programs designs then they should be implemented
now rather than being held back. The sensitivity analyses carried out by Energy
Commission staff with the local capacity annual assessment tool showed that two other
options would be useful – demand response and storage. The California ISO’s 2014-2015
Transmission Plan analyses assumed only existing demand response program capability that
was effective in relieving contingencies, such as programs located in Orange County and
responsive within 30 minutes. When California ISO results showed a deficit in the combined
L.A. Basin/San Diego region, they assumed the deficit could be satisfied by repurposing
additional demand response capacity to meet their effectiveness criteria. Accomplishing this
task much earlier, by 2021 rather than 2024, would be harder and is ultimately dependent
upon end users volunteering for these programs and sustaining their performance when the
programs are actually called upon. Developing additional storage up to the levels required
of SCE and SDG&E in D.13-10-040 would also be useful and would not necessarily involve
203

any end-user participation issues. Storage does require net additional energy, could create
new total load shape issues if recharge is not carefully controlled, and is still expensive.
Assessing Progress
The SCRP project is moving forward satisfactorily. The agency staffs continue to share
information. The CPUC has not yet been able to accelerate completion of energy efficiency
evaluation, measurement, and verification studies to validate planning assumptions.
Fortunately, load forecasts adopted in successive IEPR cycles appear to be lower than
originally anticipated, suggesting some reduction in local capacity requirements. The CPUC
and Energy Commission have approved the Carlsbad PPA and permit, respectively, but
court challenges are expected. Utilities appear to be on track in implementing the
transmission system upgrades. Mitigation measures have been refined and are nearing
readiness. Energy Commission staff have developed the analytic tool—essential to
triggering the mitigation measures—needed to assess annual requirements, but this effort
needs to be refined and continually updated.
In previous IEPR cycles, parties have raised concerns about greenhouse gas (GHG)
consequences if additional gas-fired peaking capacity were triggered as a contingency
option; however, California’s Cap-and-Trade program ensures that GHG emissions will not
increase in California. As noted in Chapter 2, California’s electric generating sector has
already achieved considerable GHG emission reductions. 276 In addition, installing sufficient
peakers to assure reliability can allow preferred resources with high energy benefits (and
GHG reduction qualities) to be pursued even more vigorously. We do not possess the ability
to assure that demand-side resources can perform a reliability function in the same manner
as dispatchable resources. Assuring that reliability standards can be maintained may require
installing some additional gas-fired capacity in the locations critical to satisfying local
capacity area needs. To the extent preferred resources are successful at demonstrating load
reduction capabilities covering a wide range of generation and transmission outage
conditions, then peakers will run even less.
Finally, close attention to local reliability issues with respect to local capacity area
requirements must be expanded to address reliability of the broader South of Path 26
region. 277 Much more OTC capacity is being shut down in southern California as a whole
than is being replaced by either new supply-side resources or demand-side load reductions.
276 Using ARB’s 2013 GHG emission inventory, GHG emissions from the electricity sector in 2013
were about 20 percent below 1990 levels.
277 Path 26 is a Western Electricity Coordinating Council designation for power flows from Northern
California to Southern California. The cut plane defining this path is essentially through the lower
San Joaquin Valley. All of the loads of SCE and SDG&E transmission access charge areas are
included, as well as a small portion of PG&E loads at the extreme southern portion of its distribution
service area.
204

As a result, Southern California is becoming more dependent upon renewable generation
located far from load centers.
The Energy Commission has been hosting a series of workshops with commissioners and
executives of key agencies since 2013 to discuss southern California reliability issues. As
evident from both previous workshops and the most recent workshop held August 17, 2015,
the Energy Commission and the collaborating agencies in the SCRP are committed to
assuring electrical reliability for the region. The coordinated planning discussed at the
workshop promotes this assurance. Implementing actions that are part of this multiagency
effort requires actions from each agency. All of the procedural opportunities to participate
in the decision-making processes of the agencies continue to exist and will allow
stakeholders to provide input if specific projects are proposed. The Energy Commission
anticipates a similar update from the staff of the key agencies next summer in the 2016 IEPR
Update proceeding at a workshop in Southern California.
August 17, 2015, Workshop Comments
On August 17, 2015, the Energy Commission hosted a public workshop on the UC Irvine
campus to review the progress since the August 2014 IEPR workshop to implement the
preliminary reliability plan and help assure electricity reliability in Southern California. The
management of the Energy Commission, the California ISO, the South Coast Air Quality
Management District, the SWRCB, and the CPUC actively participated. Staff of the agencies,
utilities, and air permitting districts provided updates on progress implementing the
CPUC’s D.14-03-004 and on transmission projects approved by the California ISO Board in
the 2012–2013, 2013–2014, and 2014–2015 Transmission Plans. Energy Commission staff, ARB
staff, and senior representatives of the South Coast Air Quality Management District and
San Diego Air Pollution Control District provided an overview of contingency plan efforts,
OTC retirement extensions, and some key air permitting issues.
Stakeholders provided a range of feedback, including the following:
• Cogentrix commented on behalf of several peaking plant owners that reactive power
could be provided by existing peaking plants that could either modify software or
install clutches that would enable them to operate as synchronous condensers
without burning any fuel. 278 Cogentrix further commented that such beneficial
changes should qualify modified peakers to be considered comparable to other
higher loading order resources, such as energy efficiency. 279
278 Cogentrix written comments on the August 17, 2015, IEPR commissioner workshop on Southern
California Electricity Reliability. http://docketpublic.energy.ca.gov/PublicDocuments/15-IEPR-
07/TN205952_20150831T154151_CalPeak_Operating_Services_LLC_Comments_Docket_No_15IEPR0
7_Sout.pdf, p. 2.
279 Ibid, p. 3.
205

• AES said that, given the shortfalls in local capacity demonstrated by Energy
Commission staff’s modeling and the California ISO presentation, it was important
to plan for the development of resources given the reliability consequences of such
shortfalls. 280
• AES also disputed the timeline in the staff report describing mitigation options for
judicial review of Energy Commission permits stating that three six month periods
was more likely even if the California Supreme Court denied such a writ. 281 AES
supported Option 3 for multiple reasons, such as it’s the lowest cost and lowest risk
to ratepayers, but also it would not be susceptible to such court appeals.
• BAMx supported the Energy Commission staff modeling tool to assess year-by-year
local capacity concerns but requested that the model be made public and that the
Energy Commission address ratepayer cost concerns in an enlarged study. 282
• The California Energy Storage Alliance (CESA) commended Energy Commission
staff for developing its modeling tool but proposed a more expansive role for storage
in resolving any identified local capacity shortfalls. CESA agreed that the CPUC
should study local capacity requirements in the 2016 LTPP rulemaking. 283
• Nevada Hydro Company requested recognition that its large pumped hydro project
at Lake Elsinore and the associated transmission line would resolve Southern
California local capacity problems. Three volumes of supporting reports were
submitted. 284
280 AES, written comments on the August 17, 2015, IEPR commissioner workshop on Southern
California Electricity Reliability. http://docketpublic.energy.ca.gov/PublicDocuments/15-IEPR-
07/TN205949_20150831T150730_Julie_Gill_Comments_15IEPR07_Southern_California_Electricity_In.
pdf, pp.2-3.
281 Ibid., p. 6.
282 BAMx written comments on the August 17, 2015, IEPR commissioner workshop on Southern
California Electricity Reliability. http://docketpublic.energy.ca.gov/PublicDocuments/15-IEPR-
07/TN205936_20150831T122755_Pushkar_Wagle_Comments_Bay_Area_Municipal_Transmission_Gr
oup_BA.pdf, p. 1.
283 CESA, written comments on the August 17, 2015, IEPR commissioner workshop on Southern
California Electricity Reliability. http://docketpublic.energy.ca.gov/PublicDocuments/15-IEPR-
07/TN205942_20150831T140956_Donald_Liddell_Comments_083115_CESA_IEPR_Comments.pdf,
pp. 1-2.
284 Nevada Hydro Company, written comments on the August 17, 2015, IEPR commissioner
workshop on Southern California Electricity Reliability.
http://docketpublic.energy.ca.gov/PublicDocuments/15-IEPR-
206

• FuelCell Energy asserted that fuel cells should be included as a preferred resource to
satisfy local capacity problems. They have minimal emissions and could be carbonneutral
if fueled by biogas, and could serve as a hydrogen source for transportation
vehicles. 285
• Sierra Club California expressed alarm that the Energy Commission’s development
of the local capacity tool and development of contingency mitigation options were
undercutting the CPUC’s Long-term Procurement Plan rulemaking, which it
asserted was the proper forum for these issues. If the Energy Commission persisted,
then Sierra Club noted a large number of assumptions that it proposed would better
characterize the low-carbon future of California and wanted these to be used in a
revised study. 286
Changing Trends in California’s Sources of Crude Oil
The Energy Commission explored changing trends in crude oil production, pricing, and
transportation safety concerns as part of the 2014 IEPR Update. In June 2014, the Energy
Commission convened a workshop to better understand the changing landscape with
respect to California’s sources of crude oil. That workshop brought together a broad set of
stakeholders for the first time and helped provide insight into the differing roles of federal,
state, and local levels of government. To build on the information gathered during last
year’s effort, and to evaluate the progress made in addressing safety concerns with the
transportation of crude-by-rail (CBR), the Energy Commission hosted an IEPR workshop
July 20, 2015, in Sacramento. This section provides updates on domestic crude oil
production trends, trends in California hydraulic fracturing activity, changes in crude oil
pricing, CBR trends, and updates on safety measures covered in the 2014 IEPR Update.
07/TN205944_20150831T142615_David_Kates_Comments_Information_on_Southern_California_Reli
abi.pdf, p. 1.
285 FuelCell Energy written comments on the August 17, 2015, IEPR commissioner workshop on
Southern California Electricity Reliability. http://docketpublic.energy.ca.gov/PublicDocuments/15-
IEPR-
07/TN205953_20150831T154105_Frank_Wolak_and_Mike_Levin_Comments_FuelCell_Energy_2015_I
EPR_C.pdf,pp. 1–4.
286 Sierra Club written comments on the August 17, 2015, IEPR commissioner workshop on Southern
California Electricity Reliability. http://docketpublic.energy.ca.gov/PublicDocuments/15-IEPR-
07/TN205959_20150831T203448_Kathryn_Phillips_Comments_Sierra_Club_Comments_on_15IEPR07.
pdf, p. 103.
207

U.S. Crude Oil Extraction Developments and Resulting Increased Output
Domestic crude oil production has continued its dramatic rebound in the United States,
largely due to the extensive use of horizontal drilling techniques and well treatment referred
to as hydraulic fracturing, or “fracking.”
Fracking is a technique used by the petroleum industry to obtain crude oil and natural gas
from geological formations that require additional effort to increase the volume of
petroleum that can be removed from an existing field. These “tight oil and gas” formations
require the rock to be fractured to enable the crude oil and natural gas to flow though the
fissures to well bores and on to the surface. As detailed in the 2014 IEPR Update, hydraulic
fracturing is not a new procedure and is estimated to have been used in more than 1 million
wells worldwide.
Much progress has been made to improve the understanding of the impacts associated with
hydraulic fracturing in California and providing public access to information. 287 For
example, Senate Bill 1281 (Pavley, Chapter 561, Statues of 2014) requires oil and gas
operators to submit quarterly water reports detailing the source, quality, and treatment of
all waters used for injection, disposal, and other oil and gas field activities. 288 The 2015 first
quarter water summary report and data tables are now publicly available and represent
filings from roughly 60 percent of oil and gas operators. 289
Production of oil in the United States was 9.7 million barrels per day during April 2015, the
highest level of output since April 1971. Figure 50 depicts the rebound of crude oil
production in the United States over the last several years, along with changes in output
from key producing states. The U.S. Energy Information Administration forecasted that
production could continue increasing and eventually exceed the all-time record output of
10.044 million barrels per day achieved during November 1970. 290
287 The Division of Oil Gas and Geothermal Resources provides extensive information related to
hydraulic fracturing activities in California at http://www.conservation.ca.gov/dog/Pages/Index.aspx.
An overview of the hydraulic fracturing reporting requirements may be viewed at
http://www.conservation.ca.gov/dog/general_information/Documents/121712NarrativeforHFregs.pdf.
288 http://www.conservation.ca.gov/dog/SB_1281/Pages/Index.aspx.
289 http://www.conservation.ca.gov/dog/SB_1281/Pages/SB_1281DataAndReports.aspx.
290 According to the Energy Information Administration’s May 2015 update of its Annual Energy
Outlook, crude oil production in the United States could reach 10.60 million barrels per day by 2020
under the “Reference Case” scenario. U.S. Crude Oil Production to 2025: Updated Projection of Crude
Types, Energy Information Administration, May 2015, Figure 1, p. 1,
http://www.eia.gov/analysis/petroleum/crudetypes/pdf/crudetypes.pdf. The annual values and
different scenarios can be found at http://www.eia.gov/analysis/petroleum/crudetypes/xls/figuredata.xlsx.
208

Figure 50: U.S. Crude Oil Production (1981-April 2015)
12,000
10,000
Chart peak of 9.173 million barrels per day - Feb. 1986
All-time peak of 10.044 million barrels per day - Nov. 1970
9.701 million barrels per day
Highest since April of 1971
Thousands of Barrels Per Day
8,000
6,000
4,000
US Crude Oil Production
North Dakota
California + OCS
3.711 million barrels per day
Highest since March 2015
Alaska
Texas
Rest of US
1.169 million barrels per day
2,000
0
Jan-1981
Dec-1981
Nov-1982
Oct-1983
Sep-1984
Aug-1985
Jul-1986
Jun-1987
May-1988
Source: Energy Information Administration
Apr-1989
Mar-1990
Feb-1991
Jan-1992
Global Crude Oil Production Trends
Dec-1992
Nov-1993
Oct-1994
The tremendous rebound in domestic crude oil production has had a direct impact on
imports into the United States. Figure 51 portrays how crude oil imports for the United
States have declined from the peak of 10.13 million barrels per day during 2005 to an
average of 7.26 million barrels per day for the first five months of 2015, a decline of 28.3
percent.
Sep-1995
Aug-1996
Jul-1997
Jun-1998
May-1999
Apr-2000
Mar-2001
Feb-2002
Jan-2003
Dec-2003
Nov-2004
Oct-2005
Sep-2006
Aug-2007
Jul-2008
Jun-2009
May-2010
Apr-2011
Mar-2012
Feb-2013
Jan-2014
Dec-2014
209

Figure 51: U.S. Crude Oil Imports (1990- 2015)
11
10.13
10
Millions of Barrels Per Day
9
8
7
7.26
6
* Y-T-D average through May.
5
1990
1991
1992
1993
1994
1995
1996
1997
1998
1999
2000
2001
2002
2003
2004
2005
2006
2007
2008
2009
2010
2011
2012
2013
2014
*2015
Source: Energy Information Administration
The increase in supply has led to lower crude oil prices, which in turn has discouraged
domestic drilling. It is possible that this steady drop in crude oil imports will not be
sustained as a growing glut in global crude oil supplies has placed downward pressure on
crude oil prices. (See below.) Figure 52 shows that by July 2015, the number of rigs deployed
to drill for oil in the United States had plummeted 56.9 percent from a peak in October 2014,
increasing the likelihood that the continued growth of domestic production could be halted
over the near-term and begin to decline.
210

Figure 52: U.S. Oil Rig Deployment Declines with Price
1,800
1,600
1,601
1,400
1,200
1,000
800
600
400
638
200
0
7/17/1987
3/18/1988
11/18/1988
7/21/1989
3/23/1990
11/23/1990
7/26/1991
3/27/1992
11/27/1992
7/30/1993
3/31/1994
12/02/1994
8/04/1995
4/05/1996
12/06/1996
8/08/1997
4/10/1998
12/11/1998
8/13/1999
4/08/2000
12/15/2000
8/17/2001
4/19/2002
12/20/2002
8/22/2003
4/23/2004
12/23/2004
8/26/2005
4/28/2006
12/29/2006
8/31/2007
5/02/2008
1/02/2009
9/04/2009
5/07/2010
1/07/2011
9/09/2011
5/11/2012
1/11/2013
9/13/2013
5/16/2014
1/16/2015
Source: Baker Hughes data – through July 17, 2015
The surge in crude oil production from the United States, coupled with the unwillingness of
Saudi Arabia and other members of the Organization of Petroleum Exporting Countries
(OPEC) cartel to reduce their own output, led to a growing imbalance between supply and
demand for crude oil that was the primary factor for placing downward pressure on prices.
Figure 53 shows the quarterly supply and demand values for crude oil since the beginning
of 2013. Global supply of crude oil began to overtake demand during the first quarter of
2014.
211

Figure 53: Global Crude Supply Imbalance (Q1 2013–Q1 2015)
96
95
1.39
1.47
2.0
1.85
1.5
94
1.01
Millions of Barrels Per Day
93
92
91
90
89
88
-0.29
-0.09
-0.80
-1.08
0.48
Supply
Demand
Supply Imbalance
1.0
0.5
0.0
-0.5
-1.0
87
-1.5
1Q 2013
2Q 2013
3Q 2013
4Q 2013
1Q 2014
2Q 2014
3Q 2014
4Q 2014
1Q 2015
Source: International Energy Agency and Energy Commission analysis
The continued build of excess supply weighed heavily on world markets, leading to a
collapse of crude oil prices that began during the summer of 2014 and continued through
the third quarter of 2015. Figure 54 illustrates the change in price for Brent North Sea crude
oil, an international benchmark type of crude oil that is a good surrogate price for foreign
sources of crude oil processed in California refineries.
212

Figure 54: Daily Brent Crude Oil Prices (2011–July 17, 2015)
140
Dollars ter Barrel
120
100
80
60
40
20
2011 2012
2013 2014
201D
46.7 percent lower than
same time last year.
0
Jan
Feb
Mar
Apr
May
Jun
Jul
Jul
Aug
Sep
Oct
Nov
Dec
Source: Energy Information Administration
Brent oil dropped 59.5 percent between June 19, 2014, and January 13, 2015. Although prices
rebounded somewhat during the first half of 2015, the downward pressure on global oil
prices is expected to continue through the fourth quarter of 2015. Absent a change in policy
by OPEC to cut back its production and yield market share, there could be even greater
downward pressure on pricing when the Iranian nuclear accord is finalized by both
countries. When also considering the downward changes in China’s economy, it becomes
less likely that crude oil prices can rebound in a meaningful way any time before late 2016.
Changing Infrastructure Trends for Crude Oil Distribution
As outlined in the 2014 IEPR Update, the dramatic increase of crude oil production has
surpassed the ability of the crude oil pipeline gathering and distribution infrastructure to
keep pace. Consequently, producers have sufficiently discounted their oil prices to make the
more expensive means of rail transportation an economically viable option for refiners
outside the shale oil regions.
CBR is a somewhat recent phenomenon. Figure 55 shows the rapid increase over the last
five years as logistical providers have ramped up the capability to load crude oil into rail
cars at production locations in Canada, North Dakota, Texas, Colorado, and New Mexico.
These projects have been recently completed to take advantage of crude oil price discounts
for Canadian and domestic crude oil, whose rapid increase in output has overwhelmed the
capacity of crude oil pipelines to transport to refineries. Shipments peaked at 1.124 million
213

arrels per day during December 2014. More recently, CBR deliveries have declined as
additional pipeline capacity for oil transportation has come on-line, providing local
producers access to cheaper pipeline transportation and the ability to charge higher prices.
This has been decreasing the incentive to use railways to transport crude oil that is more
expensive than transport by pipeline.
Figure 55: Crude Oil Transportation by Rail Tank Car
Source: Energy Commission analysis of data from the Energy Information Administration
California refiners received 1.1 million barrels of crude oil via rail during 2012. During 2013,
California refiners received 6.3 million barrels, a nearly sixfold increase within one year.
However, that upward trend did not continue during 2014 as rail oil imports declined
slightly to 5.7 million barrels. Figure 56 shows monthly CBR deliveries since January 2013.
The volumes peaked during December 2013 at nearly 1.2 million barrels but have since
declined to less than 0.3 million barrels by March 2015.
214

Figure 56: California Crude Oil Imports via Rail Tank Cars
1,400,000
1,200,000
Barrels Per Month
1,000,000
800,000
600,000
Canada
Colorado
New Mexico
North Dakota
Utah
Wyoming
Other Lower 48 States
400,000
200,000
0
January-13
February-13
March-13
April-13
May-13
June-13
July-13
August-13
September-13
October-13
November-13
December-13
January-14
February-14
March-14
April-14
May-14
June-14
July-14
August-14
September-14
October-14
November-14
December-14
January-15
February-15
March-15
Source: PIIRA data, Energy Commission analysis
California crude-by-rail deliveries have dropped off from the December 2013 peak as a
consequence of narrowing differences between international crude oil prices (like Brent
North Sea) and North American crude oil types (such as Canadian, North Dakota, and
Texas). As rapid increases in output from U.S. shale oil formations outpaced the capacity of
pipelines to transport the crude oil to market, producers were forced to discount their oil
prices such that the higher cost of rail tank car transport would be economical for refiners
purchasing their oil. Over the last 18 months, however, additional pipeline capacity has
come on-line, enabling additional shipments of crude oil by pipeline and reducing the need
for oil producers to continue providing steep discounts for their oil. This is why the Energy
Commission’s previous outlook for continued increase in CBR deliveries to California
during 2015 did not transpire.
The Energy Commission receives monthly reports from Class 1 railroad companies (Union
Pacific and BNSF Railway) for all imports and exports via rail tank car of crude oil, refined
petroleum products, and renewable transportation fuels (like ethanol and biodiesel). While
the originating state or country (such as Canada) for each shipment is provided, the type of
crude oil being transported is not. The density of crude oil being transported via rail can
vary significantly and be characterized as either heavy or light. This type of information is
important for state agencies needing to formulate different emergency response plans based
on the volume and density of crude oil moving by rail. The Energy Commission is unable to
quantify the volumes of heavy and light crude oil rail shipments based on the point of origin
215

alone and would also need to collect additional information sufficient to calculate density, 291
(such as API gravity or weight and volume for each rail tank car transporting crude oil).
Rail deliveries of crude oil to California refineries represent the smallest source, about one
percent of the more than 605 million barrels of crude oil received during 2014. Foreign crude
via marine tankers accounted for just over 47 percent, followed by roughly 40 percent from
California crude oil received via pipeline and just over 11 percent from Alaska via marine
tankers.
During 2013 and 2014, some CBR imports were transferred to tanker trucks at two locations
in California: the Kinder Morgan rail yard facility in Richmond and the SAV Patriot Rail
Company facility in Sacramento. The Sacramento CBR operation ceased activity during
early November 2014 after the permit from the Sacramento Air Quality Management
District was revoked by the issuing agency. There have been no CBR deliveries to Northern
California locations since November 2014.
Over the next couple of years, there is an increased likelihood that CBR facilities in Oregon
and Washington will be used to load marine vessels for delivery of crude oil to California
refineries. The ability of the Energy Commission to accurately quantify these deliveries and
monitor changing trends for sources and means of transportation is contingent upon the
submittal of appropriate information from all obligated parties. Cargo vessel operators are
required to provide a Notice of Arrival/Departure submittal to the U.S. Coast Guard's
National Vessel Movement Center within 24 to 96 hours of arrival/departure. 292 Access to
this type of information would allow the Energy Commission to more accurately monitor
movements of imports and exports of refinery feedstocks (such as crude oil) and
transportation fuels that may not be captured during normal data collection due to
underreporting by obligated parties.
California CBR Potential for Increased Imports
The likelihood that CBR imports to California will continue rising over the next couple of
years will depend on the number of CBR receiving facilities that are ultimately approved
and constructed within the state. At the July 20, 2015, IEPR workshop, Gordon Schremp of
the Energy Commission explained that the Commission is tracking three CBR projects that
have either received permits but not yet initiated construction or are still undergoing permit
291 One approach is for the Class 1 railroads to provide the weight of each rail tank car’s crude oil
cargo along with the volume of oil. Another method would be for the railroads to provide a measure
of the crude oil density such as the American Petroleum Institute gravity value or API gravity for
short.
292 Electronic Notice of Arrival/Departure (eNOAD) User Guide, U.S. Department of Homeland
Security, May 15, 2015,
http://www.nvmc.uscg.gov/NVMC/(S(ol1v1n4x11y4xrescinjgx4l))/Forms/eNOADUserGuide.pdf, p.
1.
216

eview. 293 If the three projects are constructed and begin operating at full capacity, the
contribution of CBR for California refiners could significantly increase from 1 percent in
2014 to 19 percent by 2017. 294 (Please see Appendix B for more information on California
CBR projects.)
It is possible that not all proposed projects will receive financing and be constructed. Those
that eventually do become operational will receive CBR deliveries that will most likely
displace imports of oil via marine tanker that are of similar quality to the properties of the
CBR oil. There are also several CBR facilities in Washington state that are operational, with
more planned. (Please see Appendix B for more information on projects.)
CBR Safety Concerns
Transportation of crude oil and other flammable material is not without risk. There have
been several derailments involving rail tank cars from which oil and ethanol have been
released. In many of these instances, there were fires and explosions that caused fatalities,
injuries, and contamination of the nearby environment. The most serious example of a CBR
derailment was in Lac-Mégantic, Quebec where 47 people were killed by an unmanned,
runaway train that derailed and exploded in this community on July 6, 2013. 295 In his
presentation at the July 20, 2015, workshop, Paul King from the California Public Utilities
Commission outlined how earlier derailments had already spurred action by government
agencies in the United States and Canada to improve safety standards for rail operations
and tank car standards, as well as additional efforts following the tragedy in Lac-
Mégantic. 296 Highlights of significant steps undertaken by California, federal, and Canadian
agencies are detailed in Appendix C.
The most notable updates in safety-related regulations associated with transportation of oil
and ethanol via rail tank cars cover three areas: operation of trains, construction standards
for rail tank cars, and oversight of oil transportation via rail within California.
293 The Alon project in Bakersfield, Valero project in Benicia, and the Phillips 66 project in Santa
Maria.
294 Integrated Energy Policy Report workshop on Trends in Crude Oil Market and Transportation,
California Energy Commission, July 20, 2015, http://docketpublic.energy.ca.gov/PublicDocuments/15-
IEPR-13/TN205401_20150720T084540_Crued_Oil_Overview__Changing_Trends.pptx, slide 35.
295 A detailed description of the accident, resulting investigation, and report issued by the
Transportation Safety Board of Canada may be viewed at http://www.tsb.gc.ca/eng/enquetesinvestigations/rail/2013/r13d0054/r13d0054.asp.
296 Integrated Energy Policy Report workshop on Trends in Crude Oil Market and Transportation,
California Energy Commission, California Public Utilities Commission, July 20, 2015,
http://docketpublic.energy.ca.gov/PublicDocuments/15-IEPR-
13/TN205403_20150720T084533_Crude_Oil_Ethanol_Railroad_Shipments.pptx, slides 28-32.
217

Operation of Trains Transporting Crude Oil or Ethanol
The traveling speed and braking capability of trains transporting oil or ethanol are two
important factors that can impact the severity of derailments involving these cargos. The
faster a train is traveling, the greater its momentum and force during a derailment. This is
why regulators have, among other efforts, focused on limiting the speed of trains
transporting oil or ethanol. This is especially the case through densely populated areas.
Recent regulations finalized by the Pipeline and Hazardous Materials Safety Administration
in May 2015 place slower speed restrictions on trains transporting oil or ethanol under
specific circumstances. 297
How quickly and effectively the braking systems in a train can be deployed are important
factors for reducing speed and impact prior to a collision or derailment. Mr. King explained,
“…when they took the conductor…and the caboose off the train, you no longer had
somebody back there… in case you had a failure of the train line system somewhere… You
didn’t have somebody back there to put the train into emergency brake application. So (an)
end-of-train device is a telemetry device to replace the caboose and the conductor,
basically.” 298 Enhanced braking will now be required for all high-hazard flammable trains
(HHFTs). 299 The systems are designed to increase the reaction time to apply brakes or use
additional locomotives within the string of rail tank cars.
By 2021, HHFTs will need to be equipped with electronically controlled pneumatic braking.
Mr. King provided a summary of these new requirements at the July 20, 2015, workshop. 300
At the workshop Commissioner Janea Scott questioned why the requirements are scheduled
to take effect so far into the future. Mr. King explained “They’ll have to retrofit old tank cars.
And they’ll have to build new ones with the electronic braking control systems on them.
And they also have to retrofit locomotives and any new ones will have to have those
297 DOT Announces Final Rule to Strengthen Safe Transportation of Flammable Liquids by Rail, U.S.
Department of Transportation. http://www.transportation.gov/briefing-room/final-rule-on-safe-railtransport-of-flammable-liquids#sthash.mUlzytpZ.dpuf.
298 Integrated Energy Policy Report workshop on Trends in Crude Oil Market and Transportation,
California Energy Commission, California Public Utilities Commission, July 20, 2015,
http://docketpublic.energy.ca.gov/PublicDocuments/15-IEPR-
13/TN205690_20150812T085120_Transcript_of_the_July_20_2015_IEPR_Commissioner_Workshop_on
_Tr.pdf, p. 68.
299 A high-hazard flammable train is defined as a continuous block of 20 or more tank cars loaded
with a flammable liquid or 35 or more tank cars loaded with a flammable liquid dispersed through a
train.
300 Integrated Energy Policy Report workshop on Trends in Crude Oil Market and Transportation,
California Energy Commission, California Public Utilities Commission, July 20, 2015, slides 11-17 and
20, http://docketpublic.energy.ca.gov/PublicDocuments/15-IEPR-
13/TN205403_20150720T084533_Crude_Oil_Ethanol_Railroad_Shipments.pptx.
218

systems. My sense is that the Federal Railroad Administration looked at how long it would
take, what it would do to the fleet if you required it too soon, and how that would impact
the cost benefit.” 301
Construction Standards for Rail Tank Cars
Besides reducing operating speeds and improving braking capabilities, the construction
standards for rail tank cars used to transport oil or ethanol must meet much stricter
specifications. These more stringent specifications apply to both newly constructed rail tank
cars and retrofitting existing rail tank cars for continued use in oil and ethanol service. These
new requirements are referred to as DOT Specification 117 cars and apply to all new rail
tank cars constructed after October 1, 2015, if they are used in HHFTs. Depending on the
type of legacy tank car being used in HHFTs, the deadline for retrofitting can be as early as
May 1, 2017 or as late as May 1, 2025. Figure 57 provides an overview of the primary safety
enhancements for the DOT 117 design. 302
Figure 57: DOT Specification 117 Rail Tank Car
Source: U.S. Department of Transportation
301 Integrated Energy Policy Report workshop on Trends in Crude Oil Market and Transportation,
California Energy Commission, California Public Utilities Commission, July 20, 2015,
http://docketpublic.energy.ca.gov/PublicDocuments/15-IEPR-
13/TN205690_20150812T085120_Transcript_of_the_July_20_2015_IEPR_Commissioner_Workshop_on
_Tr.pdf, p. 69.
302 Ibid, slide 18.
219

Oversight of Oil Transportation via Rail Within California
There are several California agencies involved in oversight of various safety-related
elements associated with the transportation of crude oil within the state. The most recent
significant changes highlighted here involve the activities of the California Office of Spill
Prevention and Response (OSPR). This agency has traditionally focused oil spill prevention
and response activities along coastal waterways. With passage of SB 861 the oversight of
this agency has now been expanded to encompass the entire state. Ryan Todd of OSPR
provided an overview of his agency and details of its expanded roles and responsibilities
during his presentation at the IEPR workshop on July 20, 2015. 303
OSPR estimates that its expanded role will encompass 250 to 300 additional operators that
must submit contingency plans for responding to a worst case spill from their operations.
Transporters of crude oil via rail tank car will also have to demonstrate sufficient financial
capabilities to fund any response and clean-up costs associated with a spill, much like the
financial responsibility requirements for importers of crude oil via marine vessel but with
lesser financial requirements due to the smaller worst case spill volumes that could result
from the derailment of a train transporting crude oil. During his presentation, Mr. Todd
explained, “…[W]e had to figure out what’s appropriate financial responsibility for the
inland part of the state. You know, a spill into a dry wash is probably generally going to be a
cleaner cleanup versus…cleaning up a tide pool. It’s much more expensive, much more
difficult to clean up generally, a coastal environment or an estuary than it is to clean up a
spill inland.” 304 These provisions are designed to help ensure that the costs of any spill are
borne by the responsible party rather than taxpayers. Emergency regulations are being
developed for these increased OSPR responsibilities and were released for comment on
August 3, 2015. 305
303 Integrated Energy Policy Report workshop on Trends in Crude Oil Market and Transportation,
California Energy Commission, Office of Spill Prevention and Response, July 20, 2015,
http://docketpublic.energy.ca.gov/PublicDocuments/15-IEPR-
13/TN205408_20150720T102553_Overview_of_the_Office_of_Spill_Prevention__Response_CA_Depar
tm.pptx, pp. 37-57.
304 Integrated Energy Policy Report workshop on Trends in Crude Oil Market and Transportation,
California Energy Commission, Office of Spill Prevention and Response, July 20, 2015,
http://docketpublic.energy.ca.gov/PublicDocuments/15-IEPR-
13/TN205690_20150812T085120_Transcript_of_the_July_20_2015_IEPR_Commissioner_Workshop_on
_Tr.pdf, p. 51.
305 The proposed OSPR regulations can be found at
https://www.wildlife.ca.gov/OSPR/Legal/Proposed-Regulations.
220

Next Steps
Although crude-by-rail deliveries into California are less than 1 percent of total supply for
refineries, this means of transportation could significantly increase by up to 19 percent if all
planned facilities are developed. There has been significant progress in development and
oversight of safety-related regulations for oil transportation by rail, including a growing
enhancement to California agency inspection and oversight. However, as discussed at the
2014 IEPR Update workshop on this same topic, the state is likely to need more data that can
enhance the state’s efforts to follow these trends and understand their implications.
Continued vigilance and coordination among local, state, federal, and Canadian
governments is needed since the most recently approved safety standards will be phased in
over a period of years (2017 through 2025) and harmonization of standards between the
United States and Canada has yet to be fully achieved.
California’s Nuclear Power Plants
In the 2013 IEPR, the Energy Commission made various recommendations related to the
safety and security of the decommissioning of San Onofre and to the continued operation of
the Diablo Canyon Nuclear Power Plant (Diablo Canyon). The decommissioning for San
Onofre is underway. Diablo Canyon continues to generate power under the current licenses,
which are set to expire in 2024 and 2025, even as Pacific Gas and Electric (PG&E) works to
address a number of regulatory and policy issues in preparation for a possible relicensing of
the plant in the near future. This section provides an update on decommissioning activities
at San Onofre, the current status of relicensing and related activities at Diablo Canyon, and
the future of spent fuel storage in California.
Decommissioning San Onofre Nuclear Generating Station
On June 7, 2013, Southern California Edison (SCE) announced it would retire San Onofre
Units 2 and 3. On June 13, 2013, SCE formally notified the Nuclear Regulatory Commission
(NRC) that it had permanently ceased operation of San Onofre Units 2 and 3 in a
Certification of Permanent Cessation of Power Operations, which was the first step in
preparing for decommissioning.
Decommissioning is a well-defined NRC process that involves transferring the used fuel into
safe storage, followed by the removal and disposal of radioactive components and
materials. The NRC permits nuclear plant operators up to 60 years to decommission a
nuclear plant; however, SCE plans to complete the full decommissioning process within 20
years. California further requires the decommissioned plant site be restored to its original
condition; this requirement involves additional activities beyond what the NRC may
require.
Actions to Date
Activities are underway to decommission and decontaminate the San Onofre facility and
continue to maintain the facility in a safe condition. SCE certified to the NRC in June and
July 2013 that all fuel had been removed from the Unit 2 and 3 reactors, respectively. In
221

September 2014 SCE submitted a Post-Shutdown Decommissioning Activities Report,
Irradiated Fuel Management Plan, and Site-Specific Decommissioning Cost Estimate to the
NRC, as required under federal regulations. The NRC notified SCE in August 2015 that the
agency had approved the Post-Shutdown Decommissioning Activities Report and
Irradiated Fuel Management Plan as submitted by SCE. SCE will continue to submit
additional information related to its decommissioning plan to the NRC during 2015 and
2016.
The decommissioning underway at San Onofre is focused upon fulfilling NRC requirements
and meeting certain NRC milestones of the decommissioning process. These activities
include obtaining, licensing changes, and submittals of decommissioning documents to the
NRC. After 2016, the focus will shift to transferring spent fuel from the spent fuel pools to a
dry cask storage facility.
In the long-term, decommissioning activities will also include environmental restoration of
the San Onofre site. The San Onofre plant lies within the boundaries of the Marine Corp’s
Camp Pendleton. Pursuant to the site lease agreement between the U.S. Navy and SCE, the
San Onofre site must be restored and remediated to the original condition of the land before
the San Onofre plant was built.
The potential costs to decommission the San Onofre plant are the focus of a regulatory
proceeding underway at the CPUC, which is the agency with regulatory jurisdiction over
the costs for decommissioning San Onofre. 306 In December 2014 SCE filed an application
with the CPUC seeking regulatory approval of the decommissioning cost estimate for Units
2 and 3. SCE estimated that the costs of decommissioning San Onofre will total $4.411 billion
(2014 dollars). License termination activities account for 48 percent of the total cost, while
spent fuel management (for example, transferring fuel to dry storage and maintaining dry
storage) accounts for 29 percent of the total estimated costs. 307 Site restoration accounts for
the remainder. Parties to the proceeding have raised concerns over the accuracy and
reasonableness of this cost estimate. One concern is that spent fuel will remain onsite for
many years after 2030, which is the date SCE has assumed that the federal government will
begin taking spent fuel from San Onofre for final nuclear waste disposal. 308 Another concern
is whether the decommissioning cost estimate should include estimates for contingencies
such as major maintenance or replacement of dry storage components in the event spent
fuel remains onsite for a lengthy period. The CPUC has not yet issued a decision in this
306 Application 14-12-007, Joint Application of SCE and SDG&E Company to Find the 2014 SONGS
Units 2 and 3 Decommissioning Cost Estimate Reasonable and Address Other Related
Decommissioning Issues.
307 SCE presentation. SONGS 2 & 3 Cost Accounting Workshop, February 24, 2015, p. 9.
308 SCE also assumed that all spent fuel from San Onofre would be removed completely by 2049.
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proceeding on the reasonableness of the decommissioning cost estimates and whether
contingencies for long-term spent fuel storage should be included.
SCE is expected to file a revised or updated decommissioning plan and cost estimate in
March 2016 when the CPUC begins the next Nuclear Decommissioning Cost Triennial
Proceeding (NDCTP). 309 In these proceedings the CPUC reviews and approves the utilities’
cost estimates for decommissioning their nuclear plants and, based on the approved cost
estimates, establishes the contribution rates to the decommissioning trust fund of each plant.
Spent Fuel Storage
In the 2013 IEPR, the Energy Commission recommended that SCE expand San Onofre’s
existing independent spent fuel storage installation and transfer spent fuel from pools into
dry casks, while maintaining compliance with the NRC requirements. SCE already has a dry
storage facility at San Onofre to store spent fuel from the retired Unit 1 reactor. Instead of
adding the spent fuel from Units 2 and 3 to the existing, above-ground independent spent
fuel storage installation, SCE plans to build a separate underground dry storage facility.
SCE may in the future elect to move the Unit 1 spent fuel currently stored in the aboveground
dry storage facility to the new underground facility.
In December 2014 SCE awarded a contract to Holtec International for the construction of a
HI-STORM (Holtec International Storage Module) storage facility at San Onofre. 310 The HI-
STORM facility will be an underground facility for the storage of spent fuel assemblies from
the decommissioned plant’s Units 2 and 3. Holtec will also be responsible for the transfer of
the spent fuel assemblies from the pools to the HI-STORM facility. In July 2014 Holtec
International submitted an application to the NRC seeking approval of an amendment to its
existing license for the HI-STORM dry storage system. The amendment provides for a
seismically enhanced version of the HI-STORM system. The NRC granted the license
amendment on September 8, 2015.
SCE was also asked to report to the Energy Commission on its progress until all spent fuel is
transferred to dry cask storage. The Union of Concerned Scientists has long advocated that
spent fuel be stored in dry casks once the spent fuel has sufficiently cooled in a pool (a
period of about five years). 311 Leaving spent fuel rods in pools longer than is needed to cool
the rods for safe dry storage is an unnecessary safety risk, particularly in a seismic hazard
area. An earthquake or other natural disaster, a malfunction, or even a terrorist attack that
leads to a loss of cooling water in a spent fuel pool poses a serious risk of the fuel rods
overheating and the release of radiation into the atmosphere. As noted above, SCE has
309 PG&E will also make a similar filing for Diablo Canyon and the Humboldt Bay nuclear plant.
SDG&E, as a part owner of San Onofre, will make the filing jointly with SCE.
310 The system in use prior to the shutdown of San Onofre is a system manufactured by Areva.
311 http://allthingsnuclear.org/dry-cask-storage-vs-spent-fuel-pools/.
223

emoved all fuel from the reactors of Units 2 and 3 to the spent fuel pools. SCE expects to
complete the transfer of spent fuel from the pools to dry cask storage by 2019. SCE’s
decommissioning cost estimate of $4.411 billion is based in part on the spent fuel remaining
in the pools for only this seven-year period. It is possible that decommissioning costs would
be higher if SCE is unable to meet its target of completing the transfer of spent fuel to dry
storage by 2019.
In March 2014, SCE sought approval from the NRC for certain exemptions from the NRC’s
emergency planning requirements. More specifically, SCE sought an exemption from the
requirements for maintaining formal offsite radiological emergency plans and a reduced
scope for onsite emergency plans. SCE’s primary justification for seeking the exemptions
was that San Onofre had ceased operating and shut down, and thus the types of possible
accidents had diminished. The Energy Commission expressed its concerns to the NRC that
approving SCE’s request would diminish the safeguards in place to protect the public’s
health and safety. With the approval of the exemption, SCE would be able to replace the
emergency plan that was in place for an operational San Onofre plant with an emergency
plan based on a “permanently defueled” plant. The Energy Commission noted in its
comments to the NRC that it will be several years before all spent fuel is removed from the
spent fuel pools and that the unique seismic hazards at San Onofre necessitate maintaining a
high level of emergency preparedness until such time as the spent fuel has been transferred
into dry storage.
On March 2, 2015, the NRC voted to approve SCE’s request for exemptions from certain
emergency planning requirements. The NRC staff recommendation explains that “the risk
of an offsite radiological release is significantly lower and the types of possible accidents are
significantly fewer, at a nuclear power reactor that has permanently ceased operations and
removed fuel from the reactor vessel than at an operating power reactor. On this basis, the
NRC has previously granted similar exemptions from [emergency planning] requirements
for permanently shut down and defueled power reactor licensees.” 312 In the past, the NRC
has granted similar emergency planning exemptions when the licensee was able to
demonstrate that, in the unlikely event of a beyond design-basis event in which a spent fuel
pool lost its cooling ability, there should be a minimum of 10 hours before the spent fuel
temperature would reach 900 degrees Celsius. SCE provided an analysis to the NRC that
more than 17 hours would be available between the time the spent fuel “is initially
uncovered (at which time adiabatic heatup is conservatively assumed to begin)” until the
temperature reaches 900 degrees. 313
312 Satorius, Mark, Policy Issue (Notation Vote), Request by Southern California Edison for
Exemptions from Certain Emergency Planning Requirements, SECY-14-0144, December 17, 2014.
http://www.nrc.gov/reading-rm/doc-collections/commission/secys/2014/2014-0066scy.pdf.
313 NRC Approved Exemptions, ML15082A204, June 4, 2015, see p. 12 of Enclosure 1.
224

Chairman Stephen Burns, Commissioner Kristine Svinicki, and Commissioner William
Ostendorff approved the request without reservation, while Commissioner Jeff Baran
approved the staff recommendation in part and disapproved it in part. 314 In particular, he
noted that San Onofre is located in a more seismically active region and is thus more likely
to experience large earthquakes. He also described a rulemaking plan from 2000, which
recommended a four-tiered approach to emergency planning for decommissioning plants
that is based on the cooling of spent fuel and associated diminished risks over time.
Long-Term Safety and Security Issues at San Onofre Site
One key issue that has emerged in the period since SCE announced the permanent closure
of San Onofre is the safety and security of the spent nuclear fuel that will remain on the San
Onofre site for an undetermined length of time. In 2014 the NRC published its final
“Continued Storage” rule. 315 The rule confirms that spent fuel may be stored in dry storage
facilities safely for an indefinite period. In the absence of a federal waste disposal facility,
the nuclear waste stored in dry casks will remain at San Onofre. This presents potential
security and safety issues not only through the mere presence of nuclear waste, but as a
result of the aging of the dry casks used for storage.
The adoption by the NRC of the Continued Storage rule presents new challenges for
California with regard to the long-term, on-site storage of spent nuclear fuel. Prior to the
NRC’s approval of the Continued Storage rule, the NRC had authorized on-site spent fuel
storage for a period of up to 30 years pursuant to the NRC’s Waste Confidence Rule. The
NRC extended this period to 60 years in 2008 when it revised the Waste Confidence Rule.
This decision prompted legal challenges in 2010 that ultimately led to a court decision in
which the court ordered the Waste Confidence Decision to be vacated.
Following the court’s decision, the NRC undertook a Generic Environmental Impact
Statement (GEIS) to study the environmental impacts, consequences, and safety of storing
spent fuel in dry cask storage facilities at reactor sites. The NRC studied three time-frames:
short-term (60 years), long-term (160 years), and indefinite term. The NRC concluded that
spent nuclear fuel could be stored safely and securely at reactor sites for any of the three
terms. The states of New York, Vermont, and Connecticut—along with several
environmental organizations—are now challenging the NRC’s final Continued Storage rule
in the U.S. Court of Appeals, arguing that the Continued Storage rule violates the National
Environmental Policy Act.
314 U.S. NRC, Commission Voting Record, Decision Item SECY-14-0144, Request by Southern
California Edison for Exemptions from Certain Emergency Planning Requirements, March 2, 2015.
http://pbadupws.nrc.gov/docs/ML1506/ML15062A141.pdf.
315 CLI-14-08.
225

The Energy Commission filed an amicus curiae brief in support of the other states’ legal
challenge of the Continued Storage rule. 316 The Energy Commission presented its concerns
that the GEIS by its very nature as a generic document fails to evaluate any local, regional,
or site specific characteristics and vulnerabilities in determining the long-term safety and
security of storing spent nuclear fuel at reactor sites. The GEIS’ failure to differentiate
between foreseeable seismic risks posed to sites within affected states like California, and
the remote and unlikely risks of seismic activity elsewhere, renders the GEIS flawed,
incomplete, and inconsistent with NEPA. The litigation brought by the states and
environmental groups is pending and until a court ruling is issued, the Continued Storage
rule provides the new framework for long-term spent fuel storage at nuclear power plant
sites.
With the Continued Storage rule in place, the choice of dry cask storage technology and the
strategies for ensuring the safety and security of spent fuel in dry storage become even more
critical. The Community Engagement Panel for San Onofre, a volunteer panel of elected
officials, technical experts, and business and environmental representatives organized by
SCE, convened a task force to review the technical literature on the specific technology SCE
intends to use for dry cask storage and long-term strategies for dry cask storage of spent
fuel. David Victor, Chairman of the Community Engagement Panel and a member of the
task force, presented his own conclusions in a paper: 317
1. A 20-year time horizon, which is the initial license period for NRC-approved dry
cask technologies, is artificial and too short. He noted that the NRC and other
industry stakeholders are considering periods longer than 20 years for dry cask
storage but their efforts may be overly focused on highly technical issues, while
overlooking the need for an overall strategy.
2. Aging casks will be an issue regardless of which vendor’s cask technology is used.
Given this reality, contingency plans to address maintenance, repairs, and even
replacement should be developed.
3. SCE should strive to transfer all spent fuel from the pools to casks as soon as feasible
as dry cask storage, in Mr. Victor’s opinion, is the safer option.
SCE, the Community Engagement Panel, and interested stakeholders continue to debate the
safety and security issues of long-term dry cask storage at San Onofre. Of particular concern
316 Motion for Leave to File Amicus Curiae Brief and Amicus Curiae Brief of the California State
Energy Resources Conservation and Development Commission, filed in State of New York, et al. v.
Nuclear Regulatory Commission in the United States Court of Appeals.
317 Mr. Victor had a fourth conclusion that SCE should select one of two vendors with a major
market presence in the United States. This conclusion is now moot with SCE’s selection of Holtec
International to provide its HI-STORM cask technology.
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for some stakeholders is the differing time horizons for 1) the likely very long period of time
in which spent fuel will remain at the SONGS site, 2) the initial NRC license period for the
HI-STORM system vis-à-vis the NRC’s own Continued Storage rule, and 3) Holtec’s
warranty to SCE of only 10 years for the HI_STORM system. How and to what extent the
stored spent fuel will be monitored for radiation leaks or cracks in the casks is another such
safety concern. Security hazards revolve around the potential for sabotage of the dry cask
storage area and the use of weapons or other means to breach the casks. These types of
concerns have led to discussions of a concept known as “defense in depth”: a multilayered
strategy of monitoring and safeguarding the spent fuel such that if one monitoring or safety
element fails, other layers are in place and function to ensure the safety and security of the
stored spent fuel. 318
There are some stakeholders who believe that SCE should use a “thick wall” dry storage
technology instead of the selected “thin wall” technology. 319 With the former option, spent
fuel rods are sealed inside thick-walled metal casks bolted closed with metallic seals
whereas in the latter option, spent fuel is placed inside thin-walled canisters and covered
with a metal or concrete outer shell for radiation shielding. In Europe, thick-walled dry cask
storage is the leading choice for storing spent fuel outside of pools. Nuclear power plant
owners in the United States have opted for the thin cask technology.
Critics of the thin-walled canister technologies say that these canisters are problematic for a
number of reasons. First, the thin-walled canisters such as the Holtec canisters SCE plans to
use at San Onfore are prone to corrosion and cracking. The canisters may be particularly
prone to corrosion due to the marine environment in which they will be located at San
Onofre. Second, the technology to inspect the Holtec canisters for corrosion or cracking does
not currently exist. Thus, there is no way of spotting cracks at an early stage before a
radiation leak could potentially occur. Third, if the canisters do develop cracks or otherwise
need to be replaced or repaired, the funds to do so have not been set aside. Aside from the
costs, it is possible that the spent fuel pool at San Onofre would have already been
demolished as part of the decommissioning process. Without a pool, transferring spent fuel
from a failing cask to a new one would be very challenging if not impossible.
There currently are no thick-walled canister systems licensed by the NRC for use in the
United States. The process to obtain a license would likely take 18 to 30 months. But the lack
of customers in the United States for this type of technology makes it unlikely that any
vendor will step forward to apply for a license from the NRC.
318 Victor, David. Safety of Long-Term Storage in Casks: Issues for San Onofre. December 9, 2014, p. 3.
319
See for example, Comments of Donna Gilmore in Docket 15-IEPR-12, May 7, 2015.
227

Diablo Canyon Status Update
Diablo Canyon Units 1 and 2 are operating under their original licenses, which are set to
expire in 2024 and 2025, respectively. Several factors related to the plant in particular and
the electricity market in general have come together to create a degree of uncertainty as to
whether Diablo Canyon will continue to generate power in the long-term. This section
presents an update on the status of relicensing Diablo Canyon and discusses those factors
that may ultimately impact the long-term operations at Diablo Canyon.
Relicensing Update
PG&E filed an application to renew the operating license for Diablo Canyon in 2009. The
NRC-led license renewal process involves both a safety review and an environmental review.
PG&E suspended relicensing activities in April 2011 to complete certain seismic studies.
PG&E subsequently provided new information to the NRC in December 2014 and February
2015 in support of its license renewal application. 320 In August 2015, the NRC held a public
meeting to brief the public on the milestones and timelines for the restarted license review
and to solicit the public’s comments on environmental issues related to Diablo Canyon. In
particular, the NRC reopened the environmental impact review to accept additional public
comments through the end of August. 321 The NRC will now develop the scope of the
environmental review and then prepare a plant-specific supplement to the Generic
Environmental Impact Statement.
During the April 2015 workshop at the Energy Commission on nuclear issues, PG&E
indicated that it had not made any decision as to whether it will operate Diablo Canyon
beyond its current licensed period, (2024 and 2025). 322 PG&E noted several factors that will
influence its decision, including whether or how it must comply with the OTC policy and any
feedback or developments arising from the recently completed seismic studies. (See below for
more details on these subjects.) 323
320 Nuclear Regulatory Commission. Letter to Mr. Edward Halpin re: Schedule Revision for the
Review of the Diablo Canyon Power Plant, Units 1 and 2, License Renewal Application. April 28,
2015.
321 Nuclear Regulatory Commission. Presentation: Diablo Canyon Power Plant, Units 1 and 2
License Renewal Environmental Scoping Meeting.
http://adamswebsearch2.nrc.gov/webSearch2/view?AccessionNumber=ML15202A098
322 April 27, 2015, Integrated Energy Policy Report workshop on Nuclear Power Plants,
http://docketpublic.energy.ca.gov/PublicDocuments/15-IEPR-
12/TN204516_20150506T152343_Transcript_for_the_April_27_2015_Nuclear_Joint_Lead_Commission
e.pdf, p. 94.
323 April 27, 2015, Integrated Energy Policy Report Workshop Transcript, p. 95.
228

In May 2015 CPUC President Michael Picker sent a letter to Christopher Johns, president of
PG&E, reminding PG&E that “review and approval of PG&E’s request for ratepayer funding
related to license extension of Diablo Canyon at the California Public Utilities
Commission…will involve a thorough assessment of the cost-effectiveness of the license
extension for Diablo Canyon considering the plant’s reliability and safety especially in light of
the plant’s geographic location regarding seismic hazards and vulnerability assessments.” 324
President Picker requested a cost-effectiveness study from PG&E, as well as a report on
PG&E’s progress in implementing any recommendations in the 2013 and pending 2015
Integrated Energy Policy Report as related to nuclear issues affecting Diablo Canyon. The costeffectiveness
study is to include PG&E’s analysis or assessment of a number of the most
important safety and security issues facing Diablo Canyon including:
• The major findings of the most recent seismic studies (discussed below).
• A full response to the Independent Peer Review Panel’s (IPRP) comments and
recommendations on the Central Coastal California Seismic Imaging Project (CCCSIP).
• A summary of the lessons learned from Japan’s Fukushima disaster.
• An assessment of the adequacy of access roads at Diablo Canyon and evacuation plans
for the current population and plant workers.
• A review of the adequacy of liability coverage in the event of a major accident or
disaster.
• A study of the waste disposal costs covering a license extension period.
• An assessment of the public’s comments and response to SCE’s decommissioning
plans for San Onofre and what the implications might be for Diablo Canyon.
• Proposals for alternative spent fuel management schemes that include the expeditious
transfer of spent fuel from the pools to dry storage and a showing that sufficient space
exists at Diablo Canyon for the storage of all spent fuel accumulated through a license
renewal period.
• An evaluation of the structural integrity of the spent fuel pools.
• An analysis of replacement power options including costs and environmental impacts.
• A detailed study of the costs, benefits and safety issues of cycling the Diablo Canyon
units to mitigate overgeneration problems on the grid.
324 CPUC letter from President Picker to Christopher Johns, President of Pacific Gas and Electric,
Diablo Canyon License Extension, May 27, 2015.
229

• An assessment of the costs for once-through cooling alternatives plus the assessment
of the Diablo Canyon Independent Safety Committee of the safety implications of such
alternatives.
• Tsunami risk and pressure vessel embrittlement studies.
• The status of INPO downgrades, (if any), and the reason for any downgrades.
• PG&E’s responses to the Diablo Canyon Independent Safety Committee’s (DCISC’s)
21 st and 23 rd annual reports.
• A status update on the litigation between PG&E and the NRC Resident Inspector
regarding the seismic design requirements of the Diablo Canyon operating license.
• PG&E’s summary of responses to or actions taken pursuant to the Energy
Commission’s recommendations in past and current IEPRs.
The CPUC recently denied a petition filed by Friends of the Earth to broadly examine the
regulatory treatment of Diablo Canyon. 325 The final decision noted that future conditions in
the state’s electric market, as well as the outcome of the OTC policy review for Diablo Canyon
and the seismic hazard reviews, may ultimately warrant a CPUC proceeding that both
considers the ratemaking treatment for Diablo Canyon and the need for any contingency
planning such as for power procurement policies.
Seismic and Tsunami Studies
Of particular focus to the Energy Commission on nuclear matters is implementation of
Assembly Bill 1632 (Blakeslee, Chapter 722, Statutes of 2006) and the AB 1632 Report
recommendations, as well as the results of research from the seismic hazard re-evaluations
associated with implementation of the Japan Lessons-Learned Near-Term Task Force
Recommendations. The NRC mandated this latter area of analysis. PG&E has completed the
two analyses of the seismic hazards at Diablo Canyon following the NRC directive and the AB
1632 recommendations.
In response to the AB 1632 Report recommendations, PG&E undertook the CCCSIP 326 and
published a final report in September 2014. The CCCSIP used advanced three-dimensional
seismic-reflection mapping to gain greater understanding of the seismic risks posed by the
fault zones surrounding Diablo Canyon. The final technical studies comprising the CCCSIP
present PG&E’s updated results of the ground-motion values that could result from an
earthquake on the faults studied under the CCCSIP. According to PG&E, the new research
325 Decision 15-04-019.
326 The CCCSIP Report is comprised of 12 technical reports and a summary that provide analyses of
key regional seismic features around the Diablo Canyon facility.
http://www.pge.com/en/safety/systemworks/dcpp/seismicsafety/report.page.
230

confirms that Diablo Canyon is designed to withstand a major earthquake on any of the
faults surrounding Diablo Canyon.
Although PG&E completed the advanced seismic studies as recommended by the Energy
Commission, PG&E did not make the research results available to outside peer reviewers
until after the final report was published. The Diablo Canyon IPRP was established by the
CPUC in 2010 to conduct an independent review of PG&E’s seismic studies. 327 However, the
IPRP was only able to review the final CCCSIP report, despite an expressed desire by the
IPRP to review a draft of the CCCSIP report before it was finalized. 328 CPUC President
Picker has directed PG&E to provide “a discussion of each of the [IPRP’s] comments and
recommendations” in a cost-effectiveness study of a license extension for Diablo Canyon. 329
The IPRP provided its own critique of the CCCSIP study in three reports (IPRP Reports 7, 8,
and 9) 330 . The IPRP concluded in Report No. 7, which addressed offshore seismic surveys, that
the CCCSIP had added to the knowledge base of the Hosgri fault slip rate and, as a result, had
decreased the uncertainty over the Hosgri fault slip rate and decreased the seismic hazard
uncertainty associated with the Hosgri fault. The IPRP’s Report No. 8 reviewed onshore
seismic surveys and, in particular, the CCCSIP’s efforts to develop and analyze a tectonic
model of the Irish Hills in the area surrounding Diablo Canyon. The IPRP concluded that the
new data contained in the tectonic model ultimately may be very valuable for understanding
the seismic hazards near Diablo Canyon. But the IPRP did not support the CCCSIP’s
interpretations of the modeled faults in the Irish Hills, finding the interpretations to be
inconsistent. The IPRP’s final report, No. 9, reviewed the CCCSIP’s analytical efforts
pertaining to onshore seismic studies in the immediate vicinity of Diablo Canyon and in
particular, the modeling of shear-wave velocities and site amplification.
Mr. Chris Wills from the California Geological Survey and the chair of the IPRP addressed
this final area in comments at the April 2015 workshop. Mr. Wills noted that he remains
concerned with the velocity modeling performed for the plant site. 331 As shown in Figure 58
below, of the different types of seismic hazard categories to understand for Diablo Canyon,
site amplification remains one of the most uncertain, in the view of the IPRP. The IPRP noted
in its Report No. 9 that PG&E used essentially the same methodology to account for site
327 CPUC Decision 10-08-003.
328 Prepared Testimony of John Geesman, Application 15-02-023, July 14, 2015, p. 6.
329
Letter from Michael Picker to Christopher Johns re: Diablo Canyon License Extension, May 27,
2015, p. 2.
330 http://www.cpuc.ca.gov/puc/energy/nuclear.htm.
331 Integrated Energy Policy Report workshop on Nuclear Power Plants, California Energy
Commission, April 27, 2015, http://docketpublic.energy.ca.gov/PublicDocuments/15-IEPR-
12/TN204516_20150506T152343_Transcript_for_the_April_27_2015_Nuclear_Joint_Lead_Commission
e.pdf, p. 58.
231

amplification in both the CCCSIP and Shoreline Fault reports. In addition, PG&E updated site
amplification factors to incorporate two new developments. The result of these actions by
PG&E was the conclusion in the CCCSIP report that the site amplification at the plant site was
lower than previously reported. Yet, the IPRP had criticized the Shoreline Fault study for
using only two earthquakes (the San Simeon and Parkfield earthquakes) to characterize site
amplification and recommended that PG&E demonstrate that specific site effects were the
reason for low site amplification. This critique by the IPRP was not addressed fully with the
more recent CCCSIP report. The IPRP and PG&E held a public meeting in September 2015 to
further discuss the 3-D velocity model for the Diablo Canyon foundation area and how
additional studies will help to improve the quantification of site amplification. The IPRP is
reviewing the Senior Seismic Hazard Analysis Committee reports to see if recommendations
made to PG&E were considered in its determinations of seismic hazards. 332
Figure 58: Seismic Hazard Categories at Diablo Canyon
Source: Chris Wills’ presentation at April 27, 2015, IEPR workshop
332 Integrated Energy Policy Report workshop on Nuclear Power Plants, California Energy
Commission, April 27, 2015, http://docketpublic.energy.ca.gov/PublicDocuments/15-IEPR-
12/TN204516_20150506T152343_Transcript_for_the_April_27_2015_Nuclear_Joint_Lead_Commission
e.pdf, pp. 61-62.
232

As part of its response to the 2011 Fukushima temblor in Japan, the NRC directed all U.S.
commercial nuclear power plants to reassess the potential seismic and flooding hazards to
their facilities. This reassessment of the seismic hazards at Diablo Canyon included an
updated probabilistic seismic hazard analysis (PSHA) using models for seismic source
characterization, ground motion characterization, and site response developed under the
Senior Seismic Hazards Analysis Committee method. PG&E submitted the updated PSHA
study to the NRC on March 12, 2015. 333
PG&E concluded that Diablo Canyon can withstand potential earthquakes, as well as
tsunamis and flooding. Figure 59 below presents PG&E’s findings from the most recent PSHA
study as compared to seismic hazard evaluations completed previously for licensing the plant
and as part of the Long-Term Seismic Program. This graph shows that the earthquake
potential at Diablo Canyon, (as measured by PG&E’s most recent study), is less than a
calculated “safety margin” using a 1991 study and less than the Hosgri exception. However,
the graph also shows that results of the 2015 PSHA analysis are above the double design
earthquake standard, which is the original design basis for the plant. After a preliminary
review of PG&E’s PSHA study, the NRC directed PG&E to undertake additional earthquake
risk analysis and to submit the additional analysis by June 2017.
Figure 59: Comparison of Diablo Canyon Response Spectra
Source: NRC Presentation, Adams Number ML15266A275, September 23, 2015, Slide 9
333 The study is available at www.pge.com/dcpp_ltsp.
233

The licensing basis of the plant is a topic of continued discussion among PG&E, seismic
experts, the NRC, and former resident inspector Dr. Michael Peck. Moreover, it is the subject
of a legal challenge by Friends of the Earth to the Atomic Safety and Licensing Board and is
likely a topic that the NRC will review in light of the recently submitted PSHA study. The
Atomic Safety and Licensing Board may rule in October 2015 on the narrow issue of whether
the NRC granted PG&E greater operational authority than provided under its current
licenses.
Since 2006, PG&E has been working to improve its understanding of the possible tsunami
hazards that could threaten the Diablo Canyon site. The initial focus of study encompassed
tsunami potential generated both by distant sources and near-shore sources (such as a
landslide). The result of this early effort was a tsunami inundation map for a section of the
California coast with grid resolution of about 150 meters. PG&E is now focusing its study
efforts on local source potential to create a tsunami with a higher level of grid resolution.
According to a review of PG&E’s analytical efforts to date by the DCISC, the “most likely
phenomenon…that could produce a tsunami as high as 10 meters (about 30 feet) at the
Diablo Canyon site is thought to be a local landslide offshore.” 334 PG&E reported to the
DCISC that technical results of its current studies will be made available in the 2014-2015
timeframe.
Safety Issues
The Energy Commission has made numerous recommendations over the years related to the
safe operations of California’s nuclear power plants, including Diablo Canyon. In its 2013
IEPR, the Energy Commission recommended that PG&E provide updated evacuation time
estimates, including a real-time evacuation scenario following an earthquake, and submit it to
the Energy Commission as part of the IEPR reporting process. PG&E stated that the utility is
working to update the Evacuation Time Estimate report and that the updated report will
incorporate an evacuation time estimate following a seismic event. 335
In 1980, the NRC adopted fire protection regulations intended to reduce the chance of
disabling fires at nuclear power plants. The NRC adopted an alternative set of fire protection
regulations in 2004 and gave plant owners the option of complying with the 1980
recommendations or the 2004 regulations, and PG&E expressed its intent to comply with the
most recent set, which involves extensive modifications to the plant and its procedures to
obtain necessary protection against fire hazards. An NRC Event Notification Report in 2012
334 Diablo Canyon Independent Safety Committee. “Twenty-Fourth Annual Report on the Safety of
Diablo Canyon Nuclear Power Plant Operations,” Volume 2, Section 3.4.
335 August 5, 2015, PG&E Supplemental Response to the CEC on Nuclear Issues, p. 2,
http://docketpublic.energy.ca.gov/PublicDocuments/15-IEPR-
12/TN205641_20150805T174531_Valerie_Winn_Comments_Pacific_Gas_and_Electric_Company_Sup
pleme.pdf.
234

identified three fire protection deficiencies and implemented a corrective action program.
PG&E submitted a license amendment request to the NRC in June 2013, which would
transition the DCPP fire protection program to a new risk-informed, performance-based
alternative. The NRC has not yet approved this license amendment request. 336
The Energy Commission has made recommendations related to the management of spent
nuclear fuel at Diablo Canyon, as it has for San Onofre. Among these is a 2013 IEPR
recommendation to evaluate the potential long-term impacts and projected costs of spent
fuel storage in pools versus dry cask storage of higher burn-up fuels in densely packed
pools, and the potential degradation of fuels and package integrity during long-term wet
and dry storage and transportation offsite. These findings are to be submitted to the Energy
Commission and the CPUC. The Energy Commission further recommended that the CPUC
require expedited transfer of spent fuel assemblies from wet pools to dry cask storage in the
decommissioning process, and that the costs of this expedited removal should be included
in the decommissioning funds before license renewal funding is granted. In a final decision
in PG&E’s 2014 General Rate Case proceeding, the CPUC directed PG&E to file a
“satisfactory plan” that complies with the Energy Commission’s recommendations for
expedited transfer of spent fuel from wet pools to dry cask storage. 337
PG&E reported in its 2017 General Rate Case application that it must keep 772 cold fuel
assemblies in the spent fuel pool to accommodate a 193 element core (four cold assemblies
available to surround one hot assembly). 338 This four-to-one ratio is the lower limit
constraint that is in compliance with NRC’s regulations for spent fuel stored in pools. PG&E
plans to complete the construction of eight dry casks in 2015 and 12 casks in 2016, allowing
PG&E to approach this ratio.
Status of Compliance with California’s Once-Through Cooling Policy
Another factor affecting the future of Diablo Canyon will be the method and costs associated
with compliance with the State Water Resources Control Board’s once-through cooling (OTC)
policy. (OTC is discussed above in the Background section of Electricity Infrastructure of
Southern California.) The policy provisions require the owner or operator of a nuclear plant to
336 August 5, 2015, PG&E Supplemental Response to the CEC on Nuclear Issues, p. 2,
http://docketpublic.energy.ca.gov/PublicDocuments/15-IEPR-
12/TN205641_20150805T174531_Valerie_Winn_Comments_Pacific_Gas_and_Electric_Company_Sup
pleme.pdf.
337 CPUC Decision 14-08-032, p. 413.
338 PG&E General Rate Case 2017, Exhibit PG&E-5, September 1, 2015, pp. 3-45 and 3-46.
235

undertake special studies to investigate alternatives to meet policy requirements. Bechtel
Power Corporation completed the special study of alternatives to OTC for Diablo Canyon. 339
Estimates of total project costs for possible solutions range from $456 million for offshore
modular wedge wire screening to more than $14 billion for dry-air cooling technology. 340
Closed-cycle cooling systems could range from more than $8 billion to $14 billion, with
modifications taking as long as 14 years to complete. Each of five closed-cycle cooling options
studied by Bechtel involves extensive modifications to the plant, each of which has the
potential to affect the operability of safety-related systems both during and following
construction. As such, the DCISC concluded that a license amendment request would likely
be required for installation of any of the five closed-cycle cooling options. 341 Furthermore, the
DCISC stated that more design details plus additional analysis would be needed to determine
if the DCISC’s safety criterion would be met.
The Energy Commission offered comments and recommendations as part of a subcommittee
of the Review Committee for Nuclear Fueled Power Plants. This subcommittee concluded that
“closed-cycle cooling is a viable technology that can ensure Diablo Canyon’s compliance with
OTC policy,” and suggested that the only definitive way to determine the costs of retrofitting
Diablo Canyon is to competitively bid the project with the appropriate risk management and
performance terms. 342 In addition, the subcommittee recommended that the SWRCB require
PG&E to bring Diablo Canyon into compliance with Track 1 of the OTC policy as a condition
of relicensing the plant, rather than requiring compliance by a specific date.
Construction costs account for a sizeable share of total project costs in the options evaluated
by Bechtel Power. The other significant cost—around $1.2 billion–$1.3 billion—would be for
replacement power costs due to unit outages during construction of the alternative cooling
option. The closed-cycle cooling options involve outages of about 18-19 months. PG&E further
estimated that the utility would incur ongoing additional costs of between $50 million to $86
339 Bechtel Power Corporation. Alternative Cooling Technologies or Modifications to the Existing Once-
Through Cooling System for the Diablo Canyon Power Plant. August 22, 2014. The complete study is
available for download at http://www.swrcb.ca.gov/water_issues/programs/ocean/cwa316/rcnfpp/.
340 Bechtel Report, Revised Report on September 17, 2014, pp. 8-9.
341 Diablo Canyon Independent Safety Committee, Letter to Mr. Jonathan Bishop of State Water
Resources Control Board, September 5, 2013. Exhibit A, p. 5.
http://www.swrcb.ca.gov/water_issues/programs/ocean/cwa316/rcnfpp/docs/dcisc_comments.pdf.
342 Subcommittee Comments on Bechtel’s Assessment of Alternatives to Once-Through-Cooling for
Diablo Canyon Power Plant, November 18, 2014.
http://www.swrcb.ca.gov/water_issues/programs/ocean/cwa316/rcnfpp/docs/subbechcom_111314.pd
f.
236

million annually for replacement power due to derating of the units at Diablo Canyon, as well
as other increased operations and maintenance costs. 343
The timeframe for elimination of OTC for Diablo Canyon lines up with the license expiration:
2024 and 2025 for Units 1 and 2, respectively. The SWRCB has the option to amend the state’s
OTC policy if the Board finds that compliance costs are out of proportion to costs previously
identified or if compliance is unreasonable based on specified factors. A decision by the
SWRCB is pending.
Role of the Plant in the California Independent System Operator’s System
In light of the uncertainty of relicensing, seismic determinations, and OTC policy, and given
the 2024 and 2025 expiration dates for Diablo Canyon Units 1 and 2, California’s energy
agencies will need to explore contingency planning in the event that Diablo Canyon is not
able to continue generating baseload power. The AB 1632 Report addresses potential impacts
of a major disruption at Diablo Canyon. 344 The study found that some generation
replacement scenarios would result in violations of reliability criteria in the event of a
Diablo Canyon shutdown, but that such violations could be mitigated without the
construction of additional transmission lines, voltage support equipment, or generation. The
study further explored mitigation for scenarios where generation was replaced entirely with
generation either north of Path 15 or south of Path 26.
Since the AB 1632 Report was published, a significant amount of new renewable resources
have been added to the system. The California ISO has expressed its concern that
overgeneration conditions will occur with increasing frequency as a result of the greater
number of renewable resources connected to the grid. (For further discussion, see Chapter
2.) During the April 2015 workshop, the issue came up as to whether Diablo Canyon has the
capability to respond flexibly (for example, ramping or load following) to certain
circumstances such as overgeneration (due to the greater number of renewable resources).
PG&E’s Jearl Strickland noted that the utility is “evaluating what type of options [it] may
have to be able to provide additional flexibility for the plant.” 345 Mr. Strickland further
clarified that the ability of the plant to ramp is “…a small percentage. It’s…in the range of
no more than 10 to 18 percent to be able to come down at any point in time for…a day-to-
343
http://www.swrcb.ca.gov/water_issues/programs/ocean/cwa316/rcnfpp/docs/pgebechcom_091214.pd
f.
344 http://www.energy.ca.gov/2008publications/CEC-100-2008-005/CEC-100-2008-005-F.PDF, p. 190.
345 Integrated Energy Policy Report workshop on Nuclear Power Plants, California Energy
Commission, April 27, 2015, http://docketpublic.energy.ca.gov/PublicDocuments/15-IEPR-
12/TN204516_20150506T152343_Transcript_for_the_April_27_2015_Nuclear_Joint_Lead_Commission
e.pdf, p. 80.
237

day type basis.” 346 In supplemental comments filed after the workshop, PG&E stated that
Diablo Canyon is unable to provide load-following services due to safety and operations
provisions that are based on 100 percent power operations. 347
In its 2012-2013 Transmission Planning Process, the California ISO also studied the grid
reliability impacts of a shutdown of Diablo Canyon. The California ISO concluded that there
would be no material “mid or long term transmission system impacts” in the absence of an
operational Diablo Canyon if renewable generation projects are developed according to the
CPUC’s RPS Portfolio. 348 The California ISO is now undertaking its 2015-2015 Transmission
Planning Process and will include a sensitivity scenario in which Diablo Canyon is assumed
to be offline in 2023. 349 The California ISO has stated that the electric grid would operate
reliably in the event of a shutdown of Diablo Canyon. There would likely be other impacts,
including a potential increase in overall GHG emissions and a potential cost impact arising
from replacement power purchase costs. However, Diablo Canyon most likely will not be
critical in meeting California GHG goals.
Assembly Bill 32 (Núñez, Chapter 488, Statutes of 2006) requires that California achieve a
statewide goal of reducing GHG emissions to 1990 levels by 2020. Although the requirement
is not sector-specific, California’s electricity system has already achieved this level of GHG
reductions as noted in Chapter 2. Further, the Pathways Study by E3 350 shows that Diablo
Canyon is not needed to meet California’s GHG goals. The study examined various
pathways to reduce GHG levels in 2030 to achieve the 2050 GHG reduction goal, and
assumes in the reference case that Diablo Canyon would not be relicensed.
346 Integrated Energy Policy Report workshop on Nuclear Power Plants, California Energy
Commission, April 27, 2015, http://docketpublic.energy.ca.gov/PublicDocuments/15-IEPR-
12/TN204516_20150506T152343_Transcript_for_the_April_27_2015_Nuclear_Joint_Lead_Commission
e.pdf, p. 84.
347 PG&E Comments: Supplemental Nuclear Response, August 5, 2015,
http://docketpublic.energy.ca.gov/PublicDocuments/15-IEPR-
12/TN205641_20150805T174531_Valerie_Winn_Comments_Pacific_Gas_and_Electric_Company_Sup
pleme.pdf, p. 1.
348 Presentation by Jeff Billinton, California Energy Commission commissioner workshop on Nuclear
Power Plants, April 27, 2015.
349 Planning Assumptions Update and Scenarios for use in the CPUC Rulemaking R.13-12-010 and
the CAISO 2015-16 Transmission Planning Process, March 4, 2015.
350 Energy+Environmental Economics (E3), 2015, Summary of the California State Agencies’
PATHWAYS Project: Long-term Greenhouse Gas Reduction Scenarios,
https://ethree.com/public_projects/energy_principals_study.php.
238

California has added a significant amount of new renewable resources to the electric system
as part of the effort to reduce GHG emissions, and will add more to meet the Governor’s 50
percent renewable goal that is a requirement under Senate Bill 350 (De León, 2015). But with
more renewable energy flowing into the grid, there is a greater need for a flexible and
responsive grid. The California ISO has expressed its concern that overgeneration
conditions will occur with increasing frequency as a result of the greater number of
renewable resources connected to the grid (for further discussion, see Chapter 2). During the
April 2015 workshop, the issue came up as to whether Diablo Canyon has the capability to
respond flexibly (for example, ramping or load following) to certain circumstances such as
overgeneration (due to the greater number of renewable resources). PG&E’s Jearl Strickland
noted that the utility is “evaluating what type of options [it] may have to be able to provide
additional flexibility for the plant.” 351 Mr. Strickland further clarified that the plant’s ability
to ramp is “…a small percentage. It’s…in the range of no more than 10 to 18 percent to be
able to come down at any point in time for…a day-to-day type basis.” 352 In supplemental
comments filed after the workshop, PG&E stated that Diablo Canyon is unable to provide
load following services due to safety and operations provisions that are based on 100
percent power operations. 353 Nevertheless, as California continues to add renewable
resources to the electric system, flexible generating resources will be increasingly needed. To
this end, CPUC President Picker directed PG&E in his April 2015 letter to prepare a detailed
study of the costs, benefits and safety issues of cycling the Diablo Canyon units to mitigate
overgeneration problems on the grid.
Nuclear Waste Storage Issues for California
The initial regulatory pact between nuclear power plant operators and the federal
government called for the federal government to take the spent nuclear fuel away from the
plants either for reprocessing or final disposal at a federally owned or managed site. For
years the federal government researched and studied building a final waste depository at
351 Integrated Energy Policy Report workshop on Nuclear Power Plants, California Energy
Commission, April 27, 2015, http://docketpublic.energy.ca.gov/PublicDocuments/15-IEPR-
12/TN204516_20150506T152343_Transcript_for_the_April_27_2015_Nuclear_Joint_Lead_Commission
e.pdf, p. 80.
352 Integrated Energy Policy Report workshop on Nuclear Power Plants, California Energy
Commission, April 27, 2015, http://docketpublic.energy.ca.gov/PublicDocuments/15-IEPR-
12/TN204516_20150506T152343_Transcript_for_the_April_27_2015_Nuclear_Joint_Lead_Commission
e.pdf, p. 84.
353 PG&E Comments: Supplemental Nuclear Response, August 5, 2015,
http://docketpublic.energy.ca.gov/PublicDocuments/15-IEPR-
12/TN205641_20150805T174531_Valerie_Winn_Comments_Pacific_Gas_and_Electric_Company_Sup
pleme.pdf, p. 1.
239

Yucca Mountain in Nevada. That effort has been mired in controversy, leaving nuclear plant
operators with no clear federal plan for removing spent nuclear fuel from plant sites for
final disposal in a safe and secure location.
In the absence of a repository at Yucca Mountain or some other geologic site, California now
faces a prolonged period of maintaining spent nuclear fuel at San Onofre, Humboldt Bay,
and other decommissioned plant sites. Chair Weisenmiller noted during the April 2015
workshop that “none of the reactors were sited with an expectation that they would be highlevel
waste sites, which they are now.” 354 The San Diego Board of Supervisors similarly
raised their concerns over the San Onofre site being used as a long-term nuclear waste site
and took the historic step of approving an effort to advocate for the removal and relocation
of all spent nuclear fuel from the San Onofre site. 355 In general, as long as high-level nuclear
waste remains at the reactor sites, these sites cannot be released for other uses. This reality
has led to a degree of support within the industry for some sort of consolidated interim
storage. Within California, some people have made the suggestion that California should
develop its own interim high-level nuclear waste storage strategy for consolidated interim
storage. 356
Developing an interim strategy to deal with the state’s nuclear waste would face a number
of significant challenges. In particular, federal jurisdiction over high-level radioactive waste
as well as existing statutory provisions in the Nuclear Waste Policy Act would need to be
addressed. The federal government would need to empower local and state legislative and
regulatory bodies to address environmental impact issues. In addition, an interim
consolidated storage site would most certainly lead to concerns that the facility would
become a de facto final repository. For this reason and others, state and local support for any
site would also be critical.
New transportation routes and plans for the safe transport of nuclear waste to a new interim
consolidated storage site would need to be developed and vetted in regulatory and public
forums. Moreover, the delays in dealing with the current accumulation of nuclear waste at
California’s nuclear sites mean that when an interim storage facility is finally opened, the
number of shipments will be markedly higher. Plans for a private interim consolidated
storage facility in Utah have stalled as a result of difficulties in siting a transport route to the
354 Integrated Energy Policy Report workshop on Nuclear Power Plants, California Energy
Commission, April 27, 2015, http://docketpublic.energy.ca.gov/PublicDocuments/15-IEPR-
12/TN204516_20150506T152343_Transcript_for_the_April_27_2015_Nuclear_Joint_Lead_Commission
e.pdf, p. 9.
355 San Diego Board of Supervisors, September 15, 2015.
356 Victor, David and T. Brown, D. Stetson. Memorandum to SONGS Community Engagement
Panel. April 13, 2015.
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planned site. 357 The challenges in addressing the state’s nuclear waste are not
insurmountable, but they are significant.
Several efforts are underway to make a consolidated interim storage facility a reality in the
not too distant future. At the federal level, the U.S. Department of Energy (DOE) has laid
out a multistep plan to move toward a consolidated interim storage facility. The first step
would be the development of a pilot interim storage facility, followed by the siting and
licensing of a larger interim storage facility. The final step would be to site and license a
permanent geologic repository. DOE’s proposals were codified in proposed legislation for
the Nuclear Waste Administration Act Amendments of 2015, a bill co-sponsored by Senator
Dianne Feinstein and supported by the Energy Commission. 358 The bill would authorize
DOE to move forward with the development of an interim storage facility as well as provide
financial benefits to communities that agree to host such a facility.
A private entity, Waste Control Specialists, announced plans to build a consolidated storage
facility in Andrews County, Texas, that attempts to work within the existing legal and
regulatory framework for high-level nuclear waste. Waste Control Specialists’ proposal calls
for the federal government to take title to spent nuclear fuel at reactor sties and then assume
responsibility for transport of the spent nuclear fuel to the Andrews County site. The federal
government would retain title of the spent nuclear fuel while the fuel is stored at the site.
Although these efforts are a positive step toward addressing the nation’s nuclear waste,
many substantial hurdles remain. First, it is very likely that any consolidated interim storage
facility would first accept nuclear waste from already-decommissioned (or non-operational)
nuclear plant sites. Second, the nuclear waste will need to be transported to the consolidated
storage facility, and these transport routes and the associated emergency planning and
impact assessments will also need to be performed.
Recommendations
Electricity Infrastructure in Southern California
• Complete Mitigation Measure Development. SCRP should finalize development of
mitigation measures, especially the details of expeditiously updating air permits for
facilities that have received the initial permit and are likely to be developed only if
contingencies are encountered.
• Maintain/Enhance Forward Assessment Capability. The SCRP agencies should
continue efforts to support Energy Commission staff in maintaining and enhancing
357 Victor, David and T. Brown, D. Stetson. “Moving SONGS Spent Nuclear Fuel Away or: The Need
for a California Waste Strategy,” April 14, 2015, p. 3.
358 http://www.energy.senate.gov/public/index.cfm/files/serve?File_id=6edbd163-d34a-41d4-997bbc0d95387b53.
241

the LCAAT tool. LCAAT should be operated periodically and results reported to the
Energy Principals.
• Initial Concerns about 2021 Deficits in L.A. Basin Local Capacity Areas should be
Studied by the California ISO. The California ISO has stated it will conduct a 2021
study to confirm or refute the concerns raised by Energy Commission Staff using the
LCAAT tool. These results should be communicated in a timely manner, and if there
are discrepancies in findings, the California ISO should provide assistance to Energy
Commission staff in upgrading the tool.
• The CPUC Should Include Local Capacity as a Topic in the 2016 LTPP. The scope
of the CPUC’s 2016 LTPP rulemaking should include local capacity requirements,
and examining intermediate time horizons such as 2020-2022 should be an explicit
focus of the assessment.
• The JRP Rulemaking should be Resurrected as a Forum for Common Assessments
of Resource Needs. JRP, Track 2 is properly scoped to provide a forum in which the
CPUC, California ISO, and Energy Commission can develop a common set of
projections about system, local, and flexible capacity requirements annually out 10
years or more. Analysis needs to be resurrected, and this process should be
completed in a manner that creates a functional assessment capability that can form
the basis for a common understanding of resource needs.
Changing Trends in California’s Sources of Crude Oil
• Collect data needed to improve emergency preparedness. The Energy
Commission will work with the appropriate state agencies to help ensure an
accurate-as-feasible accounting of the volumes and delivery locations for all
crude oil transported by rail into the state. To improve state and local emergency
response capabilities, the Energy Commission should:
• Collect data on the weight and volume or the API gravity (or density) of
crude deliveries by tank car or marine vessel into California. The Energy
Commission should collect data on the API gravity (or density) per rail tank
car. Also, shippers of crude oil via marine vessel to California from Oregon,
Washington state, and Canada should provide the Energy Commission with
the API gravity per marine vessel (tanker and barge). This information would
allow the Energy Commission to better quantify the types of crude oil being
delivered as either "heavy" or "light."
• Collect data on marine vessel arrivals and departures for transporting liquid
bulk refinery feedstocks, refined petroleum products, and renewable fuels
into or out of California. The Energy Commission should work with the US
Coast Guard and stakeholders to identify data needs and the best process for
data collection.
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• Work with the Class 1 railroad companies to determine the feasibility of
obtaining confidential routing information for all unit and manifest
shipments of crude oil into California by rail tank car on a monthly basis. If
feasible, that information would be provided through the Petroleum Industry
Information Reporting Act with appropriate confidentiality requirements.
• Work with the Class 1 railroad companies to determine the feasibility of
obtaining confidential routing information for all unit train shipments of
crude oil into California a week in advance of these shipments. If feasible,
that information would be provided through the Petroleum Industry
Information Reporting Act with appropriate confidentiality requirements.
• Collect additional data needed to follow oil extraction, transportation and
distribution trends, and understand potential climate impacts. Given the lack of
detailed trend forecasts available to the state and wide range of crude oil carbon
intensities, state agencies will coordinate and explore data gaps; determine specific
data needed to quantify emissions, carbon intensities, and so forth; and request
necessary information.
• Collect data needed to follow oil production trends in order to understand
potential climate impacts. For example, understanding trends for specific types of
crude oil production (such as oil sands, thermally enhanced oil recovery, and others)
would help inform estimates of potential climate impacts.
• Monitor development of crude-by-rail projects. The Energy Commission will
continue to monitor development and status of crude-by-rail projects within
California and the Pacific Northwest.
California’s Nuclear Power Plants
Decommissioning San Onofre Nuclear Generating Station
• Provide updates on the development of underground dry cask storage. Southern
California Edison (SCE) should provide periodic updates to the Energy Commission
on the status of the development of the new underground dry cask storage system to
be built by Holtec International. In addition, SCE should notify the Energy
Commission when the transfer of spent fuel from wet pools to the new facility
begins and SCE’s progress toward its intended target completion date of 2019.
• Provide updates on decommissioning. SCE should continue to provide progress
updates to the Energy Commission on the decommissioning of San Onfore until the
decommissioning of the site is completed.
Diablo Canyon
• Provide updates on Nuclear Regulatory Commission’s license renewal process. In
light of the re-opening of the NRC’s review for a license renewal for Diablo Canyon,
Pacific Gas and Electric (PG&E) should provide periodic progress updates to the
243

Energy Commission on any developments in the Nuclear Regulatory Commission’s
(NRC’s) process.
• Provide updates on compliance with CPUC President Picker’s itemized list. CPUC
President Picker provided a lengthy list of compliance items to be completed by
PG&E as part of any funding request for the relicensing application process. PG&E
should provide status reports on these compliance items to the Energy Commission
and the CPUC on an annual or quarterly basis, as appropriate.
• Prepare a cost-benefit study on cycling at Diablo Canyon. Pursuant to President
Picker’s directives, PG&E should prepare a detailed study of the costs, benefits, and
safety issues of cycling the Diablo Canyon units to mitigate overgeneration problems
on the grid.
• Complete planned studies on ground motion at Diablo Canyon site. PG&E should
complete the additional studies to improve the quantification of site amplification at
the Diablo Canyon site. PG&E should report on its findings to the Energy
Commission and the IPRP.
• Complete Evacuation Time Estimate and report to Energy Commission. PG&E
should complete the update of the Evacuation Time Estimate report and provide the
completed report to the Energy Commission. The updated report should incorporate
an evacuation time estimate following an earthquake.
• Provide updates on Nuclear Regulatory Commission’s review of seismic analyses.
As part of the IEPR reporting process, PG&E should provide periodic status reports
to the Energy Commission on the progress of the NRC’s review and evaluation of
the Probabilistic Seismic Hazard Analysis (PSHA) study and related seismic
information submitted by PG&E to the NRC.
• Monitor progress on flaw analysis of pressurizer nozzles. The Diablo Canyon
Independent Safety Committee should monitor PG&E’s progress in completing the
comprehensive flaw analysis of laminar flaws on the Unit 2 pressurizer nozzles and
identification of required corrective actions over the next cycle of operation, and
follow the issue until it is resolved.
Nuclear Waste Storage Issues for California
• Monitor federal waste management activities. The Energy Commission will
continue to monitor federal nuclear waste management program activities and
represent California in the Yucca Mountain licensing proceeding to ensure that
California’s interests are protected regarding potential groundwater and spent fuel
transportation impacts in California.
• Support federal development of long-term nuclear waste management facilities.
The Energy Commission continues to support federal efforts to develop an
integrated system for management and disposal of nuclear waste, including the
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establishment of a new, consent‐based approach to siting future nuclear waste
management facilities. The Energy Commission supports the proposed Nuclear
Waste Administration Act of 2015 as cosponsored by Senator Dianne Feinstein.
• Report on aging cask management. Spent fuel will be stored in thin cask storage
technology at both San Onofre and Diablo Canyon. It is highly likely that the spent
fuel stored in dry casks will remain at the nuclear plant sites for a much longer
period of time than the initial licensing period of the dry cask technology. PG&E and
SCE should report to the Energy Commission during the next IEPR cycle on
developments within the nuclear engineering community on the issue of aging cask
management and the related technological considerations.
245

CHAPTER 8:
California Drought
The drought in California has become steadily more severe over the past few years, to the
point where Governor Edmund G. Brown Jr. signed Executive Order B-29-15, 359 declaring a
state of emergency. California’s climate is shifting toward warmer winters with thinner
snowpack that affects both energy production and demand. The impacts of climate change
on the energy system include reduced hydroelectric production, reduced thermal power
plant production, and a greater need for recycled water use and efficient water use by
power plants. Pumping and treating water requires energy and these demands increase
during drought. Also, climate change and droughts lead to dry conditions that increase the
risk of fires that pose serious threats to public health and safety, including damage to energy
infrastructure—transmission and distribution lines, power plants, and substations.
Moreover, the drought is not a short-term problem. As the climate continues to change,
California must prepare for the possibility that these drought conditions may become the
norm rather than the exception. In response, many programs are being enacted to help with
long-term water-saving plans on a wide variety of fronts. For example, new efficiency
standards will reduce water use in toilets and showers. The Water Energy Technology
(WET) program is designed to advance innovative water- and energy-saving technologies
and reduce greenhouse gas (GHG) emissions. It funds technologies that can be used across a
wide variety of sectors, including agriculture, industry, and residential. Programs like these
not only help make California more drought-resilient, but reduce energy use from water
pumping, treating, and heating. Other state agencies’ water conservation and efficiency
efforts, such as the mandatory reduction targets established by the State Water Resources
Control Board (SWRCB), have similar embedded energy savings impacts of their own.
For more information about climate change, drought, and subsidence impacts on the energy
system and adaptation measures, see Chapter 9 on Climate Change Research. This chapter
summarizes actions the Energy Commission has taken to date in response to Executive
Order B-29-15, including evaluating drought impacts on the power supply and improving
water efficiency, as well as the responses of other state agencies.
Drought and Energy Impacts
Water and energy are inextricably linked. The most obvious impacts of the drought are to
hydroelectric production. Thermal power plants, however, are also affected as they, too, use
water to operate. The drought has raised questions about reliability of water supplies for
power plants and the impacts water use by power plants may have on other consumptive
359 http://gov.ca.gov/news.php?id=18910.
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uses. This section will focus on the condition of hydroelectricity supply, the amount of
water consumed annually by power plants, the reliability of those water supplies, and steps
to save water through efficiency and conservation across the power sector. The effects of
climate change on hydropower are further discussed in Chapter 9, Climate Change
Research, under Renewable Energy Generation and Hydropower. Chapter 9 also discusses
research on the effects of climate change and drought on the natural gas and petroleum
transportation fuel infrastructure, whereas this chapter focuses on the electricity sector.
Hydro Conditions
California’s hydroelectric system consists of 14,000 megawatts (MW), spread across 287
conventional hydroelectric facilities largely dependent on snowmelt (6,000 MW), 4 pumped
storage plants (2,800 MW), and 79 multipurpose reservoirs (5,200 MW). Even without the
drought, hydropower production is a declining portion of California’s in-state generation
mix as shown in Figure 60, accounting now for about 14 percent of the state’s annual
generation on average. Hydroelectric production varies considerably from year-to-year. For
instance, a six-year drought ended in 1992, and the low hydroelectric production that year
(11 percent of the state’s total power) marked the end of a 10-year decline in hydroelectric
generation. By contrast, in 1995, a wetter year, hydroelectric power approached 28 percent.
California’s hydroelectric production in 2015 is about half of recent averages.
Figure 60: Historical Hydroelectric Generation Compared to In-State Electricity Production
Source: California Energy Commission
Shortfalls in hydroelectric production are made up in a variety of ways. California facilities
using natural gas and renewable fuels are expected to generate significantly more energy in
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2015 than in past years to fill reductions of in-state hydroelectricity generation. Over the
past three years, electric generation using natural gas has remained virtually constant, but
solar generation has more than tripled.
In addition, California normally imports hydropower from the Pacific Northwest and from
Hoover Dam in the Pacific Southwest. Indeed, additional energy imports from the Pacific
Northwest are often available. This is expected to continue, despite drier conditions in the
Pacific Northwest. Conditions for hydroelectric generation in the Pacific Southwest appear
stable through 2015.
The effects of the drought and additional power replacement expenditures will not be
known immediately. For the major investor-owned utilities (IOUs), rates and power
purchase agreements are based primarily on forecasts; thus, the potential rate impacts of
low hydro generation will not be passed on to ratepayers immediately. Nonetheless, retail
rates for the major IOUs may increase this year due to other factors (for example, already
scheduled rate increases).
Drought-related outages as a result of reduced hydropower are not expected. Climate
change is leading to higher temperatures—an increase of 2 degrees over the last 120
years 360 —and it could get much hotter. As discussed in Chapter 9, climate change and
droughts lead to dry conditions that increase the risk of fires. Of the top 20 recorded major
fires in California's history, 13 have occurred since 2002. 361 California’s fire season is
becoming longer and wildfires more unpredictable as they threaten lives and the
environment. Wildfires can make the state's electric grid more susceptible to outages
because fires can take out substations, power plants, and transmission and distribution
lines. This interruption to transmission is more of a concern than outages resulting from a
reduced supply of hydropower.
Thermal Power Plant Water Uses
Water supplies for thermal plants could be vulnerable for several reasons: curtailed federal
and state water project deliveries, water rights seniority issues, reduced recycled water
amounts, insufficient carryover or banked water, or depleted groundwater access. Plant
owners are being urged to conserve and contact their water suppliers to fully understand
current circumstances, and to determine whether actions to find alternative sources are
needed or regulatory agencies need to be notified about potential production changes. In
some cases, license or certification amendments could become necessary. For this reason, the
Governor’s Executive Order on the drought grants the Energy Commission authority to
360 California Climate Tracker (http://www.wrcc.dri.edu/monitor/cal-mon/frames_version.html)
accessed on August 15, 2015.
361 Cal Fire, “Top 20 Largest California Wildfires,”
http://www.fire.ca.gov/communications/downloads/fact_sheets/20LACRES.pdf.
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expedite the processing of amendments for power plant certifications for procuring
alternative water supplies, if needed. 362
Every thermal power plant generates heat that must be removed to keep the plant running
efficiently, whether for condensing steam or cooling lubricating oil. Generally, the largest
water use is condensing steam in a condenser to allow boiler water to be reused in the boiler
cycle. Other power plant uses include, but are not limited to, cooling inlet air by evaporating
water, cooling intermediate stages of compressors, quenching high combustion temperature
to reduce oxides of nitrogen formation, steam and water injection to increase power output,
cooling lubricating oils and fluids, cleaning equipment, including solar mirrors, and sending
supplemental water to cooling towers. Most uses are integral components of enhanced
energy production, but many uses can be replaced by dry processes (for example, air-cooled
condensers and brushes to clean mirrors). Dry processes for rejecting heat will generally
result in some degradation of power plant efficiency and output.
California has a relatively modern fleet of thermal power plants that consume little water.
Since the 2003 Integrated Energy Policy Report, the Energy Commission has worked with
applicants to build new power plants in California to reduce water consumption through
the use of recycled water and water-efficient technologies such as dry cooling. These sources
and technologies provide a more environmentally responsible option and make the
associated power plants more resilient to drought conditions. Since 2004, nearly 9,000 MW
of combined-cycle projects have been built. Of that new capacity, about 34 percent use dry
cooling and 51 percent use recycled water. The use of these types of cooling has significantly
reduced freshwater demand.
Typical water consumption at power plants can vary due to technology, age, efficiency, fuel
type, location, water quality, and wastewater disposal requirements/limitations. Overall, the
California fossil fuel power plant fleet is fairly water efficient. Table 12 shows the typical
water consumption by technology type. Coastal power plants using ocean water for cooling
purposes do not consume water and, therefore, have small impact on fresh water supplies
and are not included in Table 12. The facilities using once-through cooling (OTC) do,
however, have environmental impacts such as impingement and entrainment of organisms
on intake screens and thermal loading of the water body where discharge from the power
plant occurs. As they are subject to the SWRCB’s policy on OTC, most are likely to be
replaced or shut down over the next decade. (OTC policies with respect to electricity
reliability in Southern California are discussed further in Chapter 7.)
362 Governor Edmund G. Brown, Executive Order B-29-15. Issued April 1, 2015.
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Table 12: Water Consumption Rates for Thermal Power Plants
Technology
Typical Water Consumption Ranges
Gallons per MWh
Minimum Maximum Average Use
Wet-cooled combined-cycle 200 300 250
Dry-cooled combined-cycle 5 20 13
Simple-cycle peaker – aeroderivative
(1-100 MW)
Simple-cycle peaker – frame
machine (>200 MW)
12 345 180
39 51 45
Geothermal – wet cooled 2,000 5,700 3,850
Solar thermal – dry cooled 24 52 38
Solar Thermal – wet cooled 500 1,500 1,000
Source: Energy Commission staff
Thermal Power Plant Water Supplies
In response to California’s drought and potential impacts on water sources for thermal
power plant operations, Energy Commission staff identified relatively large power plants
(75 megawatt [MW] or larger) and the water supplies they rely on for operation. Staff
reviewed all 78 operating thermal power plants that met the size criterion and were under
the Energy Commission’s jurisdiction, as well as an additional 22 nonjurisdictional power
plants. Staff determined the location of these 100 thermal power plants and the water
supply source for each power plant as one of three categories: recycled or reclaimed water,
surface water, or groundwater. 363
Energy Commission staff analyzed the water consumption at these 100 power plants,
representing 29,000 MW of installed natural gas, solar thermal, and geothermal power, to
estimate a representative water consumption rate. Since California has more than 78,000
MW 364 of installed generation, this analysis is limited to those larger thermal power plants,
excluding hydroelectric and OTC power plants since, as noted above, the OTC facilities use
water to discharge heat but do not consume it and are being phased out in compliance with
SWRCB policy. The 100 projects do not include the roughly 14,000 MW 365 of OTC power
plants as they do not use fresh water nor consume the water they withdraw from the river or
363 http://www.energy.ca.gov/siting/documents/2015-06-25_water_supplies_map.pdf.
364 http://energyalmanac.ca.gov/electricity/electric_generation_capacity.html.
365 Ibid. As of December 31, 2014, there is 14,705 MW of OTC capacity online, including the Diablo
Canyon Nuclear Plant. Natural gas-fired OTC capacity as of December 31, 2014, is 12,382 MWs—
the capacity factor of these OTC units averaged about 11 percent.
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ocean, but use it only to reject heat. As they are subject to the State Water Resources Control
Board’s (SWRCB) policy on OTC, most are likely to be replaced or shut down during the
policy compliance period.
The 100 thermal power plants examined use nearly 123,000 366 acre-feet of water per year. 367
Among these are 30 power plants that use surface water, 20 that use groundwater, and 50
that rely on recycled and degraded groundwater as their primary water source. The plants
using surface water are spread across 17 water districts, with no water district having more
than 8 percent of the total operating capacity (in megawatts). (See Figure 61.) The 20 plants
using groundwater as a primary supply are spread across 13 different groundwater basins,
limiting the effect to any groundwater basin. Only two plants are located in basins with
significant overdraft and subsidence related to groundwater pumping. These latter plants
represent about 2 percent of the 29,000 MW of operating capacity examined.
366 This is only part of the fleet, as many water intensive geothermal units are not larger than 75 MW
and are not included in this list or the estimate of average acre-feet of water per year.
367 One acre-foot is 325,851 gallons.
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Figure 61: Water Supply for Natural Gas, Geothermal, and Solar Thermal Power Plants
Source: Energy Commission staff
Surface water supplies are the most uncertain supply sources. Power plants that receive
fresh-water supply from a public supplier have generally been informed that they will
receive their contracted amount similar to other municipal and industrial users. In some
cases, however, the public supplier is delivering surface water as the primary supply, which
is subject to water rights regulated by the SWRCB. Federal and state regulators have
significantly curtailed some surface water deliveries, which has the potential to reduce
deliveries to power plants. So far, affected plants have been able to identify and access
alternative water supplies, sometimes requiring license amendment approvals by the
Energy Commission. Over the past 18 months, four projects have required and obtained
licensing amendments for water supply. To date, however, none have had to rely on the
authority for expedited licensing granted by the Governor’s Executive Order.
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Power plants operators that rely on groundwater from on-site wells generally are concerned
about the depth of groundwater and the adequacy of their wells to produce the necessary
supply. In some areas of California, groundwater levels have dropped, and modification of
well equipment has been required to maintain the necessary supply. Although adequate
supply from groundwater for the near term appears to be available, (sometimes requiring
well modification where needed), this use does not address long-term effects such as
overdraft and subsidence of the groundwater basin.
Power plants that use secondary- or tertiary-treated, recycled water as the primary supply
are considered to have the most drought-resistant supply. Many power plants in California
are priority customers for the recycled water suppliers. These power plants generally are a
customer that uses recycled water year-round, which is desirable for the recycled water
suppliers. In several cases, the supplier has specifically agreed to supply multiple power
plants first and provide other users only a portion of the supply, if there is excess available.
There is some concern about the effects of water conservation being required in the urban
sector and how that conservation may impact recycled water supply. If significant water
conservation is achieved, as directed by the recently adopted SWRCB regulations, the flows
to wastewater treatment plants that produce recycled water could be reduced. Recycled
water could also become more valuable to sell on the market. Experience thus far is that
there has been little impact on recycled water supplies, and there does not appear to be
significant concern on the part of the suppliers. 368
Energy Commission staff believes the effects of urban water conservation on recycled water
will be case-specific and depend on the source(s) of flow the treatment plant receives. In
some cases, there are significant volumes of wastewater treated at a plant to both secondary
and tertiary levels. In these cases, secondary-treated effluent is discharged where there is
little to no further human use. Any reduction in flow could be made up by treating more of
the secondary treated effluent to tertiary standards. In other areas of California, wastewater
is treated to tertiary standards, yet there are limited customers to use it, and excess is
discharged with no further human use. In these cases, even if there were reductions in
wastewater flow, there would be adequate flow to make up for the need at a power plant or
other customers. In general, municipalities that supply recycled water specifically for reuse
will plan and build only the infrastructure necessary to serve known and proposed
customers that have indicated they are willing or required to use recycled water for
operation. In those cases, supply of wastewater may not be a limitation, but the ability to
expand infrastructure to meet demand may be.
368 Most water conservation plans expect significant reductions in landscape irrigation, which do not
affect flows to waste-water treatment plants.
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Energy Efficiency and Water Appliances Regulations
In addition to tracking the impacts of the drought on the energy sector, the Energy
Commission is also focused on improving drought resiliency and energy efficiency through
new and existing programs. Among these, the Energy Commission is responsible for
adopting water efficiency standards to reduce the water consumption of appliances that use
a significant amount of water on a statewide basis. Under this authority, the Energy
Commission began investigating standards for toilets, urinals, and faucets as part of the first
phase of its 2012 Order Instituting Rulemaking Proceeding. 369
Executive Order B-29-15 authorized the Energy Commission to adopt emergency
regulations establishing standards that improve the efficiency of water appliances for sale
and installation in new and existing buildings. 370 Within seven days of the Governor’s
Executive Order, the Energy Commission adopted standards for toilets, kitchen and
lavatory faucets, and urinals. These standards are projected to save 10.3 billion gallons of
water, 30.6 million therms of natural gas, and 218 gigawatt-hours (GWh) of electricity each
year after the regulations are in effect. 371 Over 10 years, the regulations will save an
estimated 730 billion gallons of water.
On August 12, 2015, the Energy Commission adopted tiered showerhead standards. Tier I
reduces the maximum flow rate from 2.5 gallons per minute to 2.0 gallons per minute, and
Tier II will require showerheads to use no more than 1.8 gallons per minute. Tier I is in
alignment with the WaterSense specification, the California Plumbing Code, and the
California Green Building Code Tier II, which is effective in 2018. 372 The combined tiered
standards will save 38 billion gallons of water annually once all existing stock is replaced.
The Energy Commission also amended its residential lavatory faucet standards to
369 http://energy.ca.gov/appliances/2012rulemaking/notices/prerulemaking/2012-03-
14_Appliance_Efficiency_OIR.pdf.
370 http://gov.ca.gov/docs/4.1.15_Executive_Order.pdf.
371 Natural gas savings, electricity savings, and avoided GHG emissions are based on both the
reduced amount of electricity required to distribute water across the state and, for products that use
hot water, the reduced amount of energy (natural gas or electricity) required to heat water.
Additional unquantified energy savings and avoided GHG emissions may accrue from reduced
wastewater treatment.
372 U.S. EPA, “WaterSense Specification for Showerheads.”
http://www.epa.gov/watersense/docs/showerheads_finalspec508.pdf.
California Plumbing Code, Title 24, Chapter 4, section 408.2.
Department of Housing and Community Development. A Guide to the California Green Building
Standards Code (Low-Rise Residential. June 2010. http://www.hcd.ca.gov/codes/state-housinglaw/calgreenguide_complete_6-10.pdf.
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immediately implement a 1.5 gallon-per-minute requirement, saving an additional 730
million gallons of water, delaying the 1.2 gallon-per-minute standard for six months to give
manufacturers sufficient time to comply and allowing retailers to sell existing stock.
Tables 13 and 14 below show the regulatory changes and estimated savings for each
appliance, both in first-year savings and after full stock turnover.
Table 13: First-Year Savings from Water Appliance Regulatory Standards
Regulatory Changes
First-Year Savings
Original
standard
New
standard
Water
(Mgal)
Natural Gas
(million
therms)
Electricity
(GWh)
Savings
($M)
Toilets 1.6 gpf* 1.28 gpf 904.6 - 9.08 8.21
Urinals 1.0 gpf 0.125 gpf 308 - 3.10 2.31
Kitchen Faucets
2.2 gpm**
1.8 with
optional 2.2
gpm
3,290 10.78 82.9 48.56
Residential
Lavatory Faucets
Public Lavatory
Faucets
2.2 gpm
Tier I:
1.5 gpm 4,453 16 118 68
Tier II:
1.2 gpm 373
2.2 gpm 0.5 gpm 1,420 5.81 14.2 16.95
Showerheads
Tier I: 2,433 13 83 44
2.5 gpm 2.0 gpm
Tier II: 1,448 8 49 26
1.8 gpm
Total 14,256.6 53.59 359.28 214.03
Source: California Energy Commission *gpf= gallons per flush, **gpm=gallons-per-minute
373 For simplicity, first-year savings for faucets presented after Tier II takes effect because Tier I is
effective for less than the full year.
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Table 14: Annual Savings from Water Appliance Regulatory Standards After Stock Turnover
Annual Savings After Stock Turnover
Water
(Mgal)
Natural
Gas
(million
therms)
Electricity
(GWh)
Savings
($M)
GHG
Emissions
Avoided
(tons
eCO 2)
Toilets 16,990 - 171.2 154.7 58,880
Urinals 3,550 - 35.6 26.6 12,290
Kitchen
Faucets
Residential
Lavatory
Faucets
29,700 97.4 749 439
44,834 160 1,187 683
1,807,370
Public
Lavatory
Faucets
16,280 53.4 164 184
Showerheads
38,802 202 1,322 702 1,632,611
Total 150,156 512.8 3,628.8 2,189.3 3,511,151
Source: California Energy Commission
The Energy Commission is investigating additional opportunities to achieve water savings
through standards for landscape and agricultural irrigation equipment and commercial
dishwashers. In this effort to identify additional savings opportunities, it will be important
to have the cooperation and support of the investor-owned and publicly owned utilities
during development of codes and standards, as well as during implementation of incentive
programs for water-efficient appliances.
Water Appliance Rebate Program
In Executive Order B-29-15, the Governor directed the Energy Commission, jointly with the
Department of Water Resources (DWR) and the SWRCB, to implement a time-limited
statewide appliance rebate program to provide monetary incentives for the replacement of
inefficient household devices. The Energy Commission proposes to establish two programs
using this funding: a statewide rebate program and a direct-install program focused on
disadvantaged communities. The Energy Commission initially developed the programs
around an estimated budget of $30 million; however, funding for the programs has not yet
been authorized.
256

Statewide Rebate Program
The Energy Commission proposes to offer a statewide water appliance rebate program
through participating retailers. Rebates may be claimed through a simple online application,
mail-in rebate, or instant rebates at participating big box retailers (for example, Sears, Home
Depot, and Best Buy). At the outset of the program, the Energy Commission plans to focus
on appliance rebates for clothes washers, given the reliance of these appliances on heated
water (which increases GHG emissions) and their large share of indoor water consumption.
Additional appliances such as dishwashers, kitchen and lavatory faucets, and showerheads
may be considered for inclusion in the rebate program, depending on initial program
uptake.
The Energy Commission is contracting with an experienced rebate administrator to manage
the statewide rebate program. The rebate administrator will perform services that include
developing and managing a website to administer the rebate program; creating a database
to record and track all program elements; educating consumers and retailers about the
rebate program; providing estimates of available incentive funding for the program
duration; tracking estimated water savings, energy savings, and GHG emission reductions;
developing an online rebate application; receiving rebate applications and validating claims
to ensure program guidelines are met; issuing rebate checks to consumers who submit
compliant applications; and developing a point-of-sale instant rebate program at
participating big box retailers. The rebate administrator will also provide a toll-free
customer service call center and, overseen by the Energy Commission, guard against fraud,
waste, and abuse of the rebate program.
Initial rebates for clothes washers are proposed at $100 each. The Energy Commission has
selected qualifying clothes washers based on the greatest available water savings, energy
savings, and GHG reductions compared to the cost of administering a rebate program.
Eligible clothes washers must be listed in the Energy Commission’s Appliance Efficiency
Database and be ENERGY STAR®-compliant. A list of qualifying clothes washers will be
made available on the rebate program website, and only those appliance models that have
been shown to meet the specified rebate program criteria will qualify for a rebate.
The Energy Commission selected the ENERGY STAR certification as the efficiency standard
for the rebate program based on:
• The prominence ENERGY STAR brand has in the marketplace of providing
consumers with information on products that can save energy, save money, and help
reduce GHG emissions.
• ENERGY STAR-certified clothes washers use about 25 percent less energy and 40
percent less water than other washers, resulting in significant savings.
• The ENERGY STAR criteria for clothes washers changed on March 7, 2015, resulting
in greater savings.
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To calculate water savings and energy savings for clothes washers, the Energy Commission
estimates savings of 13 gallons of water per load compared to 27 gallons of water per load as
the base for older, inefficient models. 374 This is roughly consistent with ENERGY STARcertified
clothes washers that average 13 gallons of water per load. Once implemented, the
appliance rebate program anticipates issuing $100 rebates for 130,000 clothes washers, with
annual savings of 5,110 gallons of water and 212 pounds of carbon dioxide emissions per
unit.
Direct-Install Appliance Program
The direct-install appliance program is the second phase of the Energy Commission’s
drought-response incentives under Executive Order B-29-15. This program proposes to
target disadvantaged and drought-impacted communities in California by dedicating
funding to projects physically located within disadvantaged community census tracts using
the CalEnviroScreen tool.
The Energy Commission proposes to partner with the Department of Community Services
& Development (CSD) and DWR through CSD’s existing residential Low-Income
Weatherization Program by adding water-reducing measures to the existing weatherization
program, including the installation of new clothes washers, dishwashers, kitchen and
lavatory faucets, and showerheads to eligible single-family and multifamily residents. The
aim of the partnership is to leverage CSD’s ability to identify disadvantaged community
residents in need of energy-efficient, water-reducing appliances and fixtures. The intent is
not only to save water during the current drought, but also to lower GHG emissions due to
reduced water heating demand. CSD proposes to amend its existing contracts with
providers across California to include water-saving appliances in the program and include
water-saving measures in its tracking database to report water savings, energy savings, and
GHG emissions reductions.
Coordination with Other State Agencies
In addition to working directly with CSD, the Energy Commission and DWR have formed a
partnership to implement both phases of the Executive Order appliance rebate programs.
Using the same rebate administrator as the Energy Commission, DWR will offer online
rebates for water-efficient toilets and for turf replacements to residents statewide with funds
from Proposition 1 (2014). 375 Alongside the Energy Commission’s direct-install program,
DWR will provide water-efficient toilets through CSD’s Low-Income Weatherization
Program, under a separate Interagency Agreement. The DWR effort will focus on
disadvantaged communities, particularly in California’s Central Valley. Funding for this
DWR work will also use Proposition 1 funds.
374 Vickers, Amy. Handbook of Water Use and Conservation. WaterPlow Press. 2001.
375 California Water Code, Section 79750 et seq.
258

Together, the Energy Commission and DWR staff held public information and guideline
workshop meetings to inform communities and receive input on the rebate program in three
locations around the state. Future public meetings will also be held related to the directinstallation
program with CSD. The interagency coordination for both the rebate and directinstall
effort will provide the public a coordinated point of access for the toilet, clothes
washer, and turf replacement rebates and a similarly coordinated process for engaging the
direct-install program through the long-standing Low-Income Weatherization Program.
Water Energy Technology Program
In response to California's ongoing drought, Governor Brown's Executive Order B-29-15
also directed the Energy Commission to implement a statewide water energy technology
program as part of its work to address the drought. 376
To accelerate the deployment of innovative water- and energy-saving technologies and
reduce GHG emissions, the Energy Commission, jointly with DWR and the SWRCB, will
implement the Water Energy Technology (WET) Program to fund innovative technologies
for businesses, residents, industries, and agriculture that meet the following criteria:
• Document readiness for rapid, large-scale deployment (but not yet widely deployed)
in California.
• Demonstrate actual operation beyond the research and development stage.
• Display significant GHG emission reductions as a result of implementing
technologies that reduce on-site energy and water use.
In addition to the DWR and the SWRCB, the program was developed with input from other
state agencies and stakeholders participating in four public meetings held between June and
August 2015 in Fresno, Chico, Lynwood, and Pomona. 377 More than 60 comments were
received on program development and design, and these were considered in the
development of the program. 378 The Energy Commission approved the WET Rebate
Program Guidebook on July 8, 2015, contingent upon legislative approval of funding. The
rebate and grant solicitations for the WET Program will be released subsequent to funding
approval. 379
376 Governor Edmund G. Brown Jr., Executive Order B-29-15, April 1, 2015.
http://gov.ca.gov/docs/4.1.15_Executive_Order.pdf.
377 http://www.energy.ca.gov/wet/documents/index.html
378 https://efiling.energy.ca.gov/Lists/DocketLog.aspx?docketnumber=15-WATER-01
379 http://docketpublic.energy.ca.gov/PublicDocuments/15-WATER-
01/TN205314_20150709T172849_WET_Rebate_Guidebook.pdf
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Like the water appliance rebate program, the Energy Commission developed the WET
Program around an estimated budget of $30 million; however, funding for this program has
not yet been authorized. Table 15 summarizes the proposed funding areas for the WET
Program.
Table 15: Proposed Water Energy Technology Program Budget
Topic Funding Amount ($)
Phase 1. Agriculture. Rebates and Grants
Phase 2. Commercial, Industrial, and Residential Sectors.
Competitive Grants
Phase 3. Desalination (existing facilities). Competitive Grants
Administration
Total
Up to $10 million
Up to $16 million
Up to $3 million
$1 million
$30 million
Source: Energy Commission staff
This program will reduce GHG emissions by funding the use of advanced energy- and
water-saving technologies. Funded projects must reduce potable on-site energy use through
more energy-efficient equipment and reduce water use through the low- or no-water
appliances, water recycling, or other measures. This program will also fund innovations to
reduce energy use and GHG emissions from existing desalination facilities, while increasing
water production efficiency.
Once funding has been approved, the Energy Commission plans to implement the WET
Program in three phases:
• Phase 1 will focus on the agricultural sector, including rebates for high-efficiency
irrigation systems that meet specified design and equipment performance criteria,
and competitive grants for customized projects. Greater use of innovative energyand
water-saving technologies will have the added benefit of reducing water
pollution in the agriculture sector, as fertilizer use and water use are directed to
what the plant needs and eliminates excess fertilizer runoff into surface or
groundwater. Farmers will also benefit from lower energy and water costs, without
affecting crop yield.
• Phase 2 will focus on the residential, commercial, and industrial sectors, including
water and wastewater treatment providers. Grants will be available for customized
projects that reduce on-site energy and water use. Examples include installation of
innovative water-saving technologies that also reduce energy use for food service,
use of waste heat recovery and water reuse projects, and use of no- or low-water
using systems that have energy-saving benefits for industry.
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• Phase 3 will fund grants for existing desalination projects, including existing plants
and plants under construction. Projects must result in GHG emission reductions,
while increasing on-site water production efficiency. Projects must use commercially
available, innovative technologies; research projects are not eligible.
The Energy Commission has set a target of at least 10 percent of WET Program funds for
projects located in disadvantaged communities that directly benefit disadvantaged
communities. To achieve this target, the WET Program will conduct outreach in
disadvantaged communities and provide higher rebate and grant amounts for projects that
benefit disadvantaged communities. For instance, projects located in and benefitting
disadvantaged communities can receive a rebate or competitive grant that provides up to 75
percent of eligible costs, provided the projects meet applicable requirements. WET program
funding for other projects will be limited to 50 percent of eligible project costs. The projects
funded will also provide sustained economic benefits to disadvantaged communities by
decreasing energy and water costs.
State Agency Updates on the Drought
On August 28, 2015, the Energy Commission hosted a multiagency workshop focused on
the drought, with representatives from federal, state, and local agencies, as well as research,
industry, agriculture, and business groups. Within the workshop, Energy Commission staff
summarized the analyses and programs described in this chapter, while other state agencies
and other organizations provided updates on their own activities.
Several representatives summarized their research on the drought and its impacts on
California’s hydrological systems. Peter Gleick of the Pacific Institute presented data
highlighting the severity of recent temperature and precipitation anomalies, with the 36-
month period ending in 2014 being both the hottest and driest of such periods since 1895. 380
While California’s aggregate agricultural revenues are at all-time highs, this is based in part
on an unsustainable combination of unsustainable production practices, improving wateruse
efficiency, and strong markets. 381 A representative from DWR summarized a U.S.
National Air and Space Administration study on subsidence resulting from groundwater
depletion, indicating the Central Valley is sinking nearly 2 inches per month, which is
without precedent. Subsidence threatens many types of infrastructure, including water
aqueducts, pumping wells, gas pipelines, and rail lines. 382 (See Chapter 9 on Climate Change
380 Integrated Energy Policy Report workshop on California’s Drought Response, August 28, 2015,
transcript, pp. 134-135.
381 Integrated Energy Policy Report workshop on California’s Drought Response, August 28, 2015,
transcript, p. 136.
382 Integrated Energy Policy Report workshop on California’s Drought Response, August 28, 2015,
transcript, p. 88.
261

Research, Climate Impacts on the Natural Gas System, for more discussion on subsidence.)
Finally, Dan Cayan with the Scripps Institution of Oceanography highlighted recent oceanic
conditions that are historically associated with strong El Niño years. A multarviate index of
El Niño conditions through the spring and summer of 2015 suggests the potential for an
unusually large El Niño season, which is historically correlated with higher amounts of
precipitation. While encouraging from a water supply perspective, the potential confluence
of large storms, high tides, and rising sea levels could also be of concern. 383 El Niño seasons
also tend to provide more rainfall in Southern California than Northern California, which
could have implications for regional groundwater recharging. 384
Meanwhile, research from the Energy Commission’s PIER and EPIC programs has also
informed understanding of climate and the drought. 385 Key among these findings:
• Within the Sierra Nevada region, average precipitation from 2012 to 2015 has been
low, but not exceptionally so within the historical record. Average temperature,
however, has been exceptionally high.
• Using paleorecord and historical data to characterize natural variability for the U.S.
Southwest, the likelihood of severely prolonged droughts (>35 years) within this
century is between 20 and 50 percent.
• Water managers can improve reservoir management practices by incorporating
probabilistic hydrologic forecasts, rather than relying on observed precipitation.
• Researchers can identify areas of the state where there is highest suitability for
groundwater banking in agriculture soil.
• Ongoing subsidence may compromise the integrity of plugged well casings, which
risks increasing methane leakage from abandoned wells.
The representative from the California Independent System (California ISO) Operator
reported that the organization is looking at programs for better dispatch flexibility and
pumps, as well as water management to help maintain reliability and address
overgeneration issues discussed in Chapter 2. Along with this, specialized processes are
383 Integrated Energy Policy Report workshop on California’s Drought Response, August 28, 2015,
transcript, p. 43-49.
384 Integrated Energy Policy Report workshop on California’s Drought Response, August 28, 2015,
transcript, p. 43-49.
385 Integrated Energy Policy Report workshop on California’s Drought Response, August 28, 2015,
transcript, p. 159-165.
262

eing developed to help the more isolated regions of the state that rely heavily on
hydropower. 386
Several agencies are also involved in water conservation. The SWRCB oversees mandated
reductions in urban water use, including the state’s overall goal of a 25 percent reduction
relative to 2013. The SWRCB representative reported that mandatory requirements began in
June 2015, and, when combined with July 2015, reductions were averaging roughly 29
percent. 387 DWR is implementing programs that are focused on consumer incentives for
low-flow toilets and turf replacements. 388 The California Department of General Services’
representative reported that its Water Conservation Grant Program, focused on improving
water efficiency at state facilities, has supported 153 water conservation projects, with
savings totaling around 278 million gallons per year. 389 Finally, the California Public Utilities
Commission (CPUC) presented information on its water-energy nexus proceeding, intended
to determine the cost-effectiveness of joint water energy projects for utility ratepayers. As
part of this proceeding, the CPUC has developed a water-energy calculator that quantifies
the amount of energy required to move and treat water and calculates the associated
savings benefits. 390
Nonstate agency workshop participants also highlighted the efforts they were undertaking
to conserve water and provided lessons for how others might adopt them. For instance, the
University of California representative reported that the UC system is taking steps to reduce
irrigation of ornamental turf while preserving irrigation for significant plant assets,
enhancing leak detection, and expanding use of recycled water. Having completed most of
the improvements it could self-finance, the UC system is also looking into establishing a
financing program for water efficiency akin to its energy efficiency program. 391 The Los
Angeles Department of Water and Power representative reported that it is developing a
386 Integrated Energy Policy Report workshop on California’s Drought Response, August 28, 2015,
transcript, p. 36-43.
387 Integrated Energy Policy Report workshop on California’s Drought Response, August 28, 2015,
transcript, p. 108-111.
388 Integrated Energy Policy Report workshop on California’s Drought Response, August 28, 2015,
transcript, p. 85-87.
389 Integrated Energy Policy Report workshop on California’s Drought Response, August 28, 2015,
transcript, p. 125-126.
390 Integrated Energy Policy Report workshop on California’s Drought Response, August 28, 2015,
transcript, p. 72-82.
391 Integrated Energy Policy Report workshop on California’s Drought Response, August 28, 2015,
transcript, p. 120-123.
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Technical Assistance Program that offers incentives for customized water conservation
projects at large facilities. 392
The need for better data collection and data availability was also a frequent subject of
participants’ comments. The representative from the U.S. Navy Region Southwest reported
that it considers water data acquisition to be a key area of focus in its Water Strategy goal of
25 percent water reduction. A key priority is the installation of advanced metering
infrastructure, which allows for real-time analysis of water use (rather than having to wait
weeks for results). Dr. Frank Loge of the UC Davis Center for Water-Energy Efficiency
presented a tool under development that allows customers to view and compare their water
use within their neighborhood. The same tool allows for localized estimates of the energy
intensity of water pumping and delivery, which can further the understanding of energy
savings and GHG emission reductions from specific water efficiency measures. 393 The
CPUC’s water-energy nexus proceeding is also proposing a pilot for energy utilities to
provide water utilities with access to smart meter data collection information as an energy
efficiency measure. 394
Workshop participants also presented on the value and opportunities for expanding and
sustaining the water supply, including storm water capture, recycled water, and
groundwater recharging. The representative from the SWRCB reported that it is developing
the Storm Water Strategic Initiative, which aims to shift management of storm water in
ways that improve water quality and supply, including immediate support for increasing
storm water capture and use. 395 The use of recycled water also offers an opportunity to
increase the state’s supply of nonpotable water. California currently uses 600,000-700,000
acre-feet of recycled water per year for a mix of agricultural uses, landscape irrigation,
groundwater recharge, and industrial uses (including power generation, as previously
mentioned). SWRCB has established goals for increasing this by 200,000 acre-feet by 2020
and an additional 300,000 acre-feet by 2030. Toward these goals, SWRCB provided funding
in March 2014 of roughly $800 million for recycled water projects. 396 Peter Gleick of the
392 Integrated Energy Policy Report workshop on California’s Drought Response, August 28, 2015,
transcript, p. 230-231.
393 Integrated Energy Policy Report workshop on California’s Drought Response, August 28, 2015,
transcript, p. 141-151.
394 Integrated Energy Policy Report workshop on California’s Drought Response, August 28, 2015,
transcript, p. 78.
395 Integrated Energy Policy Report workshop on California’s Drought Response, August 28, 2015,
transcript, p.16.
396 Integrated Energy Policy Report workshop on California’s Drought Response, August 28, 2015,
transcript, p.113-115.
264

Pacific Institute highlighted protection of agricultural lands that can also serve as locations
for recharging depleted groundwater, particularly in the southern San Joaquin valley. 397
Recommendations
• Increase accessibility of real-time water and energy data. By providing more detailed
and accessible reports of water and energy consumption, both companies and
consumers can make impactful changes to usage and efficiency by changing habits and
technology in both the short and long-term. Investment in widespread installation of
metering technology could enable the analytics required for customers to understand
and optimize their water usage.
• Support diversification of water resources. Integrated management of water supplies
must combine variable supplies, such as storm water, and reliable supplies, such as
recycled water. Increasing the use of storm water can help reduce draw on local
reservoirs. Agricultural land can play a role through on-farm storm water capture and
groundwater recharge. Similarly, the state needs to develop broader, sustained
strategies for increasing the use of recycled water. The SWRCB has already adopted
goals of increasing recycled water usage over 2002 levels by at least one million acre-feet
per year by 2020 and two million acre-feet per year by 2030, as well as increasing storm
water usage over 2007 levels by at least 500,000 acre-feet per year by 2020 and one
million acre-feet per year by 2030. Developing adequate data for measuring progress
toward these goals remains a key priority.
• Encourage research and investment into water system improvements that promote
leak detection and minimization of water losses. Poorly designed and managed water
infrastructure can lead to tremendous amounts of water leakage and loss. In September
2014, Governor Brown signed Senate Bill 1420 (Wolk, Chapter 490) that required, among
other things, that all urban water suppliers quantify water losses in their respective
urban water management plans, beginning with plan updates that were filed July 1,
2016. Information on leaks from these updates can be used to guide future research and
investment into minimizing future water losses.
• Investigate additional opportunities to achieve water savings through appliance
efficiency standards. The near-term focus should be on landscape and agricultural
irrigation equipment, as well as commercial dishwashers. When identifying additional
savings opportunities, it will be important to have the cooperation and support of the
investor-owned and publicly owned utilities through codes and standards proposals
and implementation of incentive programs for water-efficient appliances.
397 Integrated Energy Policy Report workshop on California’s Drought Response, August 28, 2015,
transcript, p. 139-140.
265

• Encourage efficient designs of home hot water delivery systems. The length of piping
between the water heater and each fixture, the pipe diameter, and the material from
which the pipe is made can all have a significant effect on the hot water delivery system
efficiency because those factors determine the volume of water stored within the
delivery system. The volume of stored water affects how long it takes for hot water to
reach each fixture and the temperature retention of the water as it is delivered; systems
with the least stored volume waste the least amount of water and energy.
• Continue the CPUC’s Evaluation of the Water-Energy Nexus. The CPUC recently
authorized pilot programs to examine whether utility-sponsored water saving projects
can provide sufficient ratepayer benefit to qualify as energy efficiency projects. The
CPUC has developed a Water-Energy Calculator to help evaluate such programs. If
water savings programs can be reliably expected to enhance energy efficiency, there
may be added opportunities for electric utilities to sponsor such programs in the future.
• Implement and sustain consumer incentives for water conservation. In 2015, California
state agencies have begun developing and implementing several incentive programs
designed to encourage water conservation, including water appliance rebates; direct
installations of toilets, faucets, and other water appliances; turf replacement rebates; and
early market deployment of innovative water technologies. Local water agencies have
also begun offering incentives of their own. As initial results from these projects become
available, the programs can be reviewed, revised (if needed), and expanded to further
maximize these benefits.
266

CHAPTER 9:
Climate Change Research
Introduction
Addressing climate change is the driving force in California’s energy policy. The energy
sector is the leading source of climate pollutants—accounting for about 80 percent of the
state’s greenhouse gas (GHG) emissions. As discussed throughout this report, the state is
working to dramatically reduce its GHG emissions through multipronged efforts to advance
the Governor Edmund J. Brown Jr.’s 2030 goals to:
• Double energy efficiency in existing buildings (Chapter 1) and advance low-carbon
heating fuels (Chapter 6).
• Increase renewable energy to 50 percent (Chapter 2 for renewable generation and
Chapter 3 for transmission planning to support increased use of renewable energy).
• Reduce petroleum use in the transportation sector by 50 percent (Chapters 4 and 6).
In turn, climate change affects how energy is used (see Chapter 5 on the electricity forecast)
and is likely to lead to future droughts like the one California is currently experiencing,
which also affects energy use and production (Chapter 8). To meet the state's long-term
GHG reduction goals, advancement of each of these efforts will require additional research
and development to help new technologies come to market. This chapter is focused on
research on climate science as it applies to California's energy system.
In April 2015, Governor Edmund G. Brown Jr. issued an Executive Order (B-30-15) 398 that set
a goal to reduce emissions to 40 percent below 1990 levels by 2030. This builds on historic
Global Warming Solutions Act of 2006 (Núñez, Chapter 488, Statutes of 2006) that requires
California to reduce GHG emissions to 1990 levels by 2020. The 2030 goal will guide
midterm regulatory policy and investments in California and maintain momentum to
reduce GHG emissions to 80 percent below 1990 levels by 2050.
Executive Order B-30-15 also directed state agencies to strengthen California’s preparedness
for climate change. As discussed in more detail in the Introduction, Executive Order B-30-15
directed the California Natural Resources Agency to update the state’s climate adaptation
plan every three years and ensure that its provisions are fully implemented. The updates
must include information on vulnerabilities of each sector, including energy, and take into
account differential impacts across California’s geographic regions. In support of these
efforts, the Governor ordered the state to continue its rigorous climate change research
program which is focused on understanding the impacts of climate change and how best to
398
http://gov.ca.gov/news.php?id=18938.
267

prepare, mitigate, and adapt to such impacts. This comprehensive research program is laid
out in the Climate Change Research Plan for California. 399
The Energy Commission through its research program and outreach efforts, such as the
Integrated Energy Policy Report (IEPR), has been a leader in conducting and supporting
cutting edge climate research related to energy sector resilience. The 2013 IEPR included a
discussion of the vulnerability of the energy sector to climate change and strategies to
safeguard it, with a focus on the electricity sector. This chapter summarizes new research
findings on the vulnerability of California’s energy system since the 2013 IEPR including
analysis of the vulnerability and potential adaptation options for the natural gas sector and
petroleum transportation fuels. The chapter closes with recommendations on next steps for
further research on adaptation to climate change in the energy sector.
Vulnerability and Adaptation Options
California’s energy system is vulnerable to a variety of climatic changes, including impacts
from changes in temperature and precipitation patterns, extreme events (including wildfire,
inland flooding, and severe storms), and sea-level rise. 400, 401 Some impacts to the energy
sector, including more frequent and severe extreme heat episodes and decreasing snowwater
content in the northern Sierra Nevada, are already becoming evident. 402 Historical
climatic data will not suffice to support future management of energy systems, nor public
health or environmental management as they relate to energy, as the climate is diverging
from its historical “envelope.” In other words, key climate parameters are starting to move
beyond historically observed variability at a rate that makes historical data a poor predictor
of future climate. This phenomenon, commonly called nonstationarity, may be at work in
historical annual temperature data for California and the world. (See Figure 62.) However,
there are not yet enough data to conclude definitively whether California is already outside
of the envelope. There are two important features to note in Figure 62 below. First, the
natural fluctuations, or variability, of temperature at the planetary scale are less pronounced
than in California. Second, 2014 was the hottest year on record in California; annual
399
Climate Action Team. Climate Change Research Plan for California. 2015.
400 Franco, Guido, Mark Wilson. 2005. Climate Change Impacts and Adaption in California. California
Energy Commission. Publication Number: CEC-500-2005-103-SD.
401 Stoms, David, Guido Franco, Heather Raitt, Susan Wilhelm, Sekita Grant. 2013. Climate Change
and the California Energy Sector. California Energy Commission. Publication Number
CEC‐100‐2013‐002.
402 Office of Environmental Health Hazard Assessment. Indicators of Climate Change in California
Report Summary. 2013.
268

temperature moved far outside the envelope of natural variability. 403 It is also important to
note that most of the warming in California occurred during the winter season, contributing
to snowpack reduction in the Sierra Nevada.
Figure 62: Global and California Temperature Anomalies
Temperature Deviations from Long-term Average (ᴼF)
4
2014
3
2
1
0
-1
Global anomalies
-2
California anomalies
-3
1920 1930 1940 1950 1960 1970 1980 1990 2000 2010 2020
Source: California Climate Tracker and NASA
Planning for the energy sector in California must work under the assumption that future
climatic conditions will be beyond the envelope of prior experience; however, this does not
mean that the energy sector has to operate in an information vacuum. Many impacts of the
changing climate regime are known. The California Coastal Commission, for example, has
determined that sufficient information exists that sea-level rise must be taken into account in
permitting major new, long-lived facilities in the coastal zone. 404 Still, there are clear areas
for future research that would better inform the process of making the energy sector more
resilient to climate impacts.
403 The deviations are from the 1949 to 2005 average. Absolute temperature in 2014 in California was
59.4 °F, which is a deviation of 3.3 °F from the 1949 to 2005 average temperature. This is both the
greatest deviation from the average and the highest annual temperature experienced in California.
404 California Coastal Commission, Sea Level Rise Policy Guidance: Interpretive Guidelines for
Addressing Sea Level Rise in Local Coastal Programs and Coastal Development Permits, August
2015, http://www.coastal.ca.gov/climate/slrguidance.html.
269

The Vulnerability of California’s Energy Sector
The impacts of climatic changes on California’s energy system include decreased efficiency
of thermal power plants and substations; decreased capacity of transmission lines; risks to
energy infrastructure from extreme events, including sea-level rise, coastal flooding, and
wildfires; less reliable hydropower resources; and increased peak electricity demand. 405
The types and severity of impacts vary across the electricity, natural gas, petroleum, and
transportation sectors and vary geographically. Over the past several years, the Energy
Commission has supported research to identify these potential impacts and investigate
magnitude, distribution, and adaptation options. A few key examples from recently
completed research on climate impacts on energy supply (including infrastructure and
capacity) and energy demand are described below. To date, significantly more research has
been done on electricity than on other aspects of the energy sector like natural gas or
transportation fuels.
Climate Impacts to the Electricity System
As outlined in the 2013 IEPR, California has invested considerable resources to understand
the potential impacts of climate change on the electricity system. 406, 407 Figure 63 illustrates
the potential impacts of climate change for the six states in the southwest United States,
including California.
405 Stoms, David, Guido Franco, Heather Raitt, Susan Wilhelm, Sekita Grant. 2013. Climate Change
and the California Energy Sector. California Energy Commission. Publication Number
CEC‐100‐2013‐002.
406 California Energy Commission. 2013. 2013 Integrated Energy Policy Report. Publication Number:
CEC-100-2013-001-CMF.
407 Stoms, David; Franco, Guido; Raitt, Heather; Wilhelm, Susan; Grant, Sekita. 2013. Climate Change
and the California Energy Sector. California Energy Commission. Publication Number
CEC‐100‐2013‐002.
270

Figure 63: Vulnerabilities to Climate Change in the Electricity Sector
Source: Assessment of Climate Change in the Southwest United States, 2013, Chapter 12
The rest of this section focuses on scientific information generated in the two years since the
release of the 2013 IEPR. Recent studies indicate that the severity of the financial costs to the
electricity system from climate impacts depend on whether the system is designed to reduce
GHG emissions or not. 408 The U.S. Environmental Protection Agency (U.S. EPA) engaged
research groups using different models of the electricity system for an analysis of costs
associated with a business-as-usual scenario and two policy scenarios. 409 The policy
scenarios assume global climate mitigation efforts in concert with deep GHG reductions in
the United States. As a result, these scenarios experience much lower ambient temperatures
408 Many mitigation measures in the electricity sector are also adaptive. See, for example, discussions
of renewable energy in this chapter.
409 These are 1) POL4.5 CS3, an emissions reduction policy and temperature pathway that are
consistent with a radiative forcing target of 4.5 watts per meter square, along with cumulative power
sector emissions reductions of 8.9 percent from 2015-2050; and 2) POL3.7 CS3, an emissions
reductions policy and temperature pathway consistent with a radiative forcing target of 3.7 watts per
meter square, with no emissions reduction policy. McFarland, J., Y. Zhou, L. Clarke, P. Sullivan, J.
Colman.2015. “Impacts of Rising Air Temperatures and Emissions Mitigation on Electricity Demand
and Supply in the Unites States: A Multi-Model Comparison.” Climatic Change. Volume 131, Issue 1,
p. 113.
271

than the business-as-usual scenario. Prior work on energy scenarios has assumed an
electricity infrastructure that is static and compared the changes in demand under different
climate regimes, or has estimated changes in the electricity system without considering
climate impacts. The U.S. EPA’s study considered both changes to the electricity system and
climate impacts, for example, increased temperatures leading to greater demand for the
electricity required for cooling. The policy scenarios in the U.S. EPA’s work simulated the
changes needed in the electricity system to reduce emissions to levels that are compatible
with climate stabilization 410 , such as 4.5 watts per meter square by 2050. 411
The climate effects simulated included the overall increased demand of electricity in the
United States and the degraded efficiency of thermal power plants due to higher
temperatures. The researchers found similar costs for both the business-as-usual and the
policy scenarios. 412 This controverts the commonly held belief that substantial reductions of
GHG emissions are expensive and increase overall costs. However, because the business-asusual
scenario experienced higher temperatures than in the policy scenarios, the businessas-usual
scenario saw increases in electricity demand and, therefore, required more
generating capacity. These extra costs are more or less equivalent to the additional
investments required to decrease electricity sector GHG emissions by nearly 50 percent by
2050. 413 In other words, the cost of mitigation (reducing GHG emissions) in the electricity
systems was roughly equivalent to the cost of serving the increased electricity demand of a
hotter climate in the business-as-usual scenario.
This finding is in agreement with an Energy Commission study, which found that higher
temperatures at the end of this century would require about a 40 percent increase of
generation capacity under a scenario not involving GHG emission reductions (business-asusual).
414 The U.S. EPA also supported similar studies for other sectors of the U.S. economy,
such as public health, agriculture, forestry, and water resources. Its summary report Climate
410 Climate stabilization refers here to the maximum amount of extra energy per unit of time absorbed
by the Earth above pre-industrial levels. The extra energy is measured in watts per square meters.
411 McFarland, J., Y. Zhou, L. Clarke, P. Sullivan, J. Colman.2015. “Impacts of Rising Air
Temperatures and Emissions Mitigation on Electricity Demand and Supply in the Unites States: A
Multi-Model Comparison.” Climatic Change. Volume 131, Issue 1, pp. 11-125.
412 The study considered only the direct costs of serving increased generation demand in all
scenarios; however, the study did not estimate or compare costs of other climate impacts, for example
damage to infrastructure from sea-level rise, across scenarios.
413 Ibid.
414 Sathaye, Jayant; Dale, Larry; Larsen, Peter; Fitts, Gary; Koy, Kevin; Lewis, Sarah; Lucena, Andre.
2012. Estimating Risk to California Energy Infrastructure From Projected Climate Change. California
Energy Commission. Publication Number: CEC‐500‐2012‐057.
272

Change in the United States: Benefits of Global Action, 415 released in June 2015, concludes that
global GHG mitigation avoids costly damages in the United States, the benefits of mitigation
increases with time, and adaptation reduces overall damages to certain sectors.
The 2013 IEPR included a 10-year peak electricity demand forecast to 2024 using climate
scenarios the Scripps Institution of Oceanography (Scripps) developed for the Energy
Commission. The forecast estimated a potential peak electricity demand of up to 1.6
gigawatts (GW), equivalent to the generating capacity of two large power plants. The 2013
forecasts were based on the climate scenarios driven by the results of global climate models
that were used for the 2007 Intergovernmental Panel on Climate Change (IPCC)
Assessment. 416 For the 2015 IEPR, Scripps developed an improved method to translate the
outputs from a new suite of climate models used for the 2014 IPCC Assessment 417 into
climate projections for California. As explained in Chapter 5, the results for peak electricity
demand are very similar to the prior study, forecasting that higher temperatures may
increase peak demand by up to 1.2 GW and increase overall annual electricity demand by
2026. 418
Climate Impacts on Renewable Energy Generation and Hydropower
By 2020, California’s Renewables Portfolio Standard requires 33 percent of electricity used in
California to be generated by eligible renewable resources. Governor Edmund G. Brown Jr.
set a goal of increasing this to 50 percent by 2030. 419 Large hydropower is not eligible to
meet the state’s renewable energy targets under statute, but it provides an important source
of electricity for California. (See Chapter 2 for more information about meeting the state’s
renewable goals). Figure 64 shows the close relationship between annual precipitation from
October 1 to September 30 (water year) and hydropower generation in July through
September. For more information about the current drought, including how it is affecting
the state’s energy system and California’s response to it, see Chapter 8.
415 U.S. Environmental Protection Agency. 2015. Fuel and Carbon Dioxide Emissions Savings Calculation
Methodology for Combined Heat and Power Systems.
416 IPCC. 2007: Climate Change 2007: Synthesis Report. Contribution of Working Groups I, II and III to
the Fourth Assessment Report of the Intergovernmental Panel on Climate Change (Core Writing
Team, Pachauri, R.K and Reisinger, A. [eds.]). IPCC, Geneva, Switzerland, 104 pp.
417 IPCC. 2014: Climate Change 2014: Synthesis Report. Contribution of Working Groups I, II and III to
the Fifth Assessment Report of the Intergovernmental Panel on Climate Change (Core Writing Team,
R.K. Pachauri and L.A. Meyer [eds.]). IPCC, Geneva, Switzerland, 151 pp.
418 Kavalec, Chris. 2015. California Energy Demand Updated Forecast, 2015-2025. California Energy
Commission, Electricity Supply Analysis Division. Publication Number: CEC-200-2014-009-CMF.
419 Inaugural Address. Remarks as prepared January 5, 2015. Edmund G. Brown Jr.
273

Figure 64: Hydropower Generation in July-September and Annual Water-Year Precipitation
Source: Generation from the Energy Information Administration, precipitation from the California Climate Tracker
With climate change, patterns of precipitation in California are expected to continue shifting
toward rain rather than snow, which California has traditionally relied on as a natural
reservoir, storing water for the drier summer months. The shift from snow to rain appears to
be due to increased temperatures. As shown in Figure 64, there has traditionally been a
close link between hydropower generation and annual precipitation 420 that falls prior to the
summer; however, higher temperatures may disrupt that relationship. The changing
precipitation patterns may mean a reduction in California hydropower in the hotter months
of the year. 421 Having a better understanding of climate change impacts on hydropower is
critical to modeling the Northern California electricity system.
In addition to the problems of reduced snowpack, hydropower faces a less certain future
from the possibility of temperature-exacerbated droughts. Some scientists argue that climate
change will substantially increase the risk of drought because high temperatures increase
420 Annual precipitation here is measured by water years.
421 Rheinheimer, D.E., Scott T. Ligare, Joshua H. Viers. 2012. Water and Energy Sector Vulnerability to
Climate Warming in the Sierra Nevada: Simulated the Regulated Rivers of California’s West Slope Sierra
Nevada. California Energy Commission. Publication Number: CEC-500-2012-016.
274

the transport of water from land to atmosphere via evaporation and transpiration.
422, 423
Chapter 8 discusses the need to prepare for a future in which drought is the norm rather
than the exception in California.
The severity of the current drought is evident in Figure 65, that shows temperature and
precipitation in the last 115 years in the Sierra Nevada region. As illustrated in Figure 66, the
average winter (defined as the months of December, January, and February) over the past
four years was not only dry, but unusually hot. Precipitation—especially snow—in the
Sierra Nevada is of primary importance for hydropower generation. The combination of dry
and warm temperatures in that region tends to exacerbate water scarcity for summer power
generation because under those conditions precipitation tends to fall as rain instead of
snow. Furthermore, under dry and hot conditions more water than usual is “lost” to
evaporation and transpiration. This one-two punch of decreased snowpack and increased
evapotranspiration has led some studies to conclude that the current drought is the most
severe in the last 1,000 years. 424
Figure 65: Sierra Nevada Region Temperature (°F) and Precipitation (inches) for Winter
(December, January, and February) in the Last 115 Years Plotted as Four-Year Averages
35
Precipitation (inches)
30
25
20
15
10
5
0
32 33 34 35 36 37 38 39 40
Temperature (°F)
2012-15
Source: California Climate Tracker
422 Diffenbaugh, N. S., Daniel L. Swain, Danielle Touma. 2015. “Anthropogenic Warming Has
Increased Drought Risk in California.” Proceedings of the National Academy of Sciences 112:3931-3936.
423 Mann, M.E., Peter H. Gleick. 2015. “Climate Change and California Drought in the 21st Century.”
Proceedings of the National Academy of Sciences, Vol. 112 no. 13, 3858-3859.
424 Griffin, D., K. J. Anchukaitis. 2014. “How Unusual Is the 2012–2014 California Drought?” Geophys.
Res. Lett. 41:2014GL062433+.
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Research supported by the Energy Commission has included analyses of high-elevation
reservoirs mainly used to produce hydropower 425, 426, 427, 428, 429 and low-elevation units such
as Folsom Lake near Sacramento that are designed primarily to store water for consumption
in cities and agricultural fields 430, 431, 432 and for flood protection. These were separate studies
that did not consider the hydraulic connection between high- and low-elevation units.
Understanding that connection is critical, however, because climate impacts may result in
high-elevation units releasing substantially higher water flows in the wintertime (see Figure
66), somewhat hampering the flood protection function of low-elevation units.
425 Vicuña, Sebastian, Rebecca Leonardson, John A. Dracup, Michael Hanemann, Larry Dale. 2006.
Climate Change Impacts on High-Elevation Hydropower Generation in California’s Sierra Nevada: A Case
Study in the Upper American River. California Energy Commission. Publication Number: CEC-500-
2005-199-SF.
426 Vicuña, Sebastian, John A. Dracup, Larry Dale. 2009. Climate Change Effects on the Operation of Two
High-Elevation Hydropower Systems in California. California Energy Commission. Publication Number:
CEC-500-2009-019-D.
427 Madani, K., J.R. Lund.2010. “Estimated Impacts of Climate Warming on California’s High-
Elevation Hydropower.” Climatic Change, Vol. 102, No. 3-4, pp. 521–538.
428 Guegan, Marion, Kaveh Madani, Cintia B., Uvo. 2012. Climate Change Effects on High-Elevation
Hydropower System with Consideration of Warming Impacts on Electricity Demand and Pricing. California
Energy Commission. Publication Number: CEC-500-2012-020.
429 Rheinheimer, D.E., Scott T. Ligare, Joshua H. Viers. 2012. Water and Energy Sector Vulnerability to
Climate Warming in the Sierra Nevada: Simulated the Regulated Rivers of California’s West Slope Sierra
Nevada. California Energy Commission. Publication Number: CEC-500-2012-016.
430 Lund, Jay R., Tingju Zhu, Marion W. Jenkins, Stacy Tanaka, Manuel Pulido, Melanie Taubert,
Randy Ritzema, Inês Ferriera. 2003. Climate Warming & California's Water Future. pp. 1-10.
431 Georgakakos, K. P., Graham, N. E., Carpenter, T. M., & Yao, H. 2005. “Integrating
Climate‐Hydrology Forecasts and Multi‐Objective Reservoir Management for Northern
California.” Eos, Transactions American Geophysical Union. AGU 86:122-127.
432 Georgakakos, K. P., Nicholas E. Graham, Aris P. Georgakakos . 2007. Integrated Forecast and
Reservoir Management (INFORM) for Northern California: System Development and Initial Demonstration.
California Energy Commission. Publication Number: CEC‐500‐2006‐109.
276

Figure 66: Simulated Operations for Upper American River Project System During
Three Periods
Average monthly Spills (m^3/s)
30
25
20
15
10
5
Historic 1975-2009
Early 21st Century
Late 21st century
0
O N D J F M A M J J A S
Source: Adapted from Vicuña et al., 2011
Sources of geothermal energy are tied to underground systems fed by rainwater and
snowmelt. Geothermal power plants reinject groundwater from the geothermal resource to
replenish the system. 433 Geothermal power plants tend to decline in productivity over time
because the resource is used faster than is naturally replenished by rainwater and snowmelt.
At the Geysers geothermal power plant near Santa Rosa, California, treated wastewater is
used to replenish the geothermal resource and help stabilize declining productivity. 434 If
patterns and location of rainwater or snowmelt change, or the availability of rainwater or
snowmelt declines, this could affect natural long-term recharge rates, potentially increasing
the need for outside water to replenish the productivity of geothermal resources.
Solar photovoltaic (PV) systems tend to be less efficient at higher temperatures. 435
Projections for the Southwest suggest efficiency reductions on the order of 0.7 to 1.7 percent
433 Clark, C.E., C.B. Harto, J.L. Sullivan, M.Q. Wang. 2011. Water Use in the Development and Operation
of Geothermal Power Plants.
434 “The Santa Rosa Geysers Recharge Project Celebrates 10 Year Anniversary”. 2013. http://ci.santarosa.ca.us/news/Pages/UtilitiesNewsRel.aspx.
435 U.S Department of Energy. 2013. “Photovoltaic Cell Conversion Efficiency Basics.”
277

with higher temperatures in 2050. 436 Information on whether and where patterns of
excessive heat may change in California due to climate change can help inform research on
solar PV systems to improve performance on hot days. Similarly, additional studies on
whether and where wind patterns in California may change due to climate change 437 can
help inform wind energy planning, forecasting, and integration as California increases the
proportion of electricity it consumes from wind energy. The scientific understanding of how
climate change may affect solar and wind resources has not substantially changed since the
release of the 2013 IEPR. In other words, projections of changes in solar and wind regimes
for the California region have not matured enough to provide a clear picture of potential
changes. A recent paper noted that wind performance depends not only on wind speed, but
on the density of the air; unfortunately, there are substantial uncertainties in the projections
of both parameters. 438
Climate Impacts on the Natural Gas System
Aspects of the energy system are vulnerable to sea-level rise and intense storms. Recent
work on natural gas infrastructure in the San Francisco Bay and Sacramento/San Joaquin
Delta sheds light on the nature of that vulnerability and on the importance of dynamic
modeling to assess risk. The islands of the Sacramento-San Joaquin Delta contain crucial
natural gas infrastructure: transmission lines, underground natural gas storage facilities,
distribution infrastructure, and abandoned natural gas wells. The islands—and the
infrastructure they house—rely on levees to protect them from flooding. Prior research
using satellite data suggested that the levees and Delta islands may be subsiding, 439 leaving
the islands and the natural gas infrastructure more vulnerable to flooding. That enhanced
risk is compounded by projected sea-level rise.
A recent study led by University of California, Berkeley, uses high-resolution
hydrodynamical modeling to investigate the impacts of an extreme storm event coupled
with sea-level rise on natural gas pipelines in the Bay Area and the Delta, as well as the
436 Bartos, Matthew D., Mikhail V. Chester. “Impacts of Climate Change on Electric Power Supply in
the Western United States.” Nature Climate Change, 5, pp. 748-752. 2015. Macmillan Publishers
Limited.
437 Rasmussen, D. J., T. Holloway, and G. F. Nemet. 2011. Opportunities and Challenges in Assessing
Climate Change Impacts on Wind Energy—A Critical Comparison of Wind Speed Projections in
California.” Environmental Research Letters 6:024008+.
438 Bartos, Matthew D., Mikhail V. Chester. “Impacts of Climate Change on Electric Power Supply in
the Western United States.” Nature Climate Change, 5, pp. 748-752. 2015. Macmillan Publishers
Limited.
439 Brooks, Benjamin A., Deepak Manjunath. 2012. Twenty-First Century Levee Overtopping Projections
from InSAR-Derived Subsidence Rates in the Sacramento-San Joaquin Delta, California: 2006–2010.
California Energy Commission. Publication Number: CEC-500-2012-018.
278

California coast. 440 This work was a substantial improvement over previous models that are
either too coarse in scale to simulate flooding events in the Delta or do not capture the
dynamic processes associated with storm events. These dynamic processes include wave
action, diurnal tides, and short-term peak water levels—all of which are critical in
determining actual risks to infrastructure.
According to the study, the Delta levees are not at risk from overtopping from an extreme
storm (100-year event) in the absence of sea-level rise and in the absence of substantial
further subsidence, provided that "prepared" is defined as no overtopping from a storm. If
such a storm event were paired with a 1.4 meter sea-level rise—which is a possible, highend
2100 estimate for California—then the storm would pose extensive risk to critical
natural gas infrastructure, as well as other energy-related and transportation infrastructure.
Such risks include inundation of roughly 400 miles of transmission lines, including
backbone transmission at Antioch, key transmission on Sherman Island, and transmission
loops in San Jose, San Francisco, and Sacramento. Moreover, under such conditions,
inundation of natural gas storage at MacDonald Island is indicated. 441
Even with this new information, risks may still be underestimated because the research did
not account for subsidence of Delta levees, which exacerbates impacts of sea level due to
lowering levee crests. Given the importance of subsidence in the Delta, the Energy
Commission’s Public Interest Energy Research (PIER) Natural Gas Research and
Development program has an ongoing interagency agreement with the U.S. Geological
Survey to deploy a new portable Light Detection and Ranging system and determine the
actual level of subsidence in key levees protecting islands with important natural gas
infrastructure. While other monitoring systems like aircraft sampling would take months or
years to return data, the Light Detection and Ranging surveys will be available within a few
days of field collection. This new Light Detection and Ranging system has the potential to
substantially lower the costs of periodic surveying of the Delta levees.
Another story related to climate change and subsidence appears to be unfolding in the
interior of California, where subsidence that is linked to heavy reliance on groundwater in
the absence of surface water supplies 442 may be exposing abandoned natural gas wells and
natural gas pipelines. Subsidence can be geographically uneven and result in deformation
440 Radke, J., et al., 2015. Assessment of Bay Area Gas Pipeline Vulnerability to Sea Water. University of
California, Berkeley. Public Interest Energy Research report in preparation.
441 Ibid.
442 Scanlon, Bridget R., Claudia C. Faunt, Laurent Longuevergne, Robert C. Reedy, William M. Alley,
Virginia L. McGuire, Peter B. McMahon. 2012. Groundwater Depletion and Sustainability of
Irrigation in the US High Plains and Central Valley.” Proceedings of the National Academy of Sciences.
USGS Staff – Published Research. Paper 497.
279

or even ruptures of underground pipelines. 443 The risk to the natural gas supply system
from climate-linked subsidence is an emerging issue that has not yet been thoroughly
studied; yet the potential for improving climate adaptation for the energy sector while
lowering GHG emissions makes this a priority area for future research on climate-related
impacts to the natural gas system. For information on the effects of subsidence as a result of
increased groundwater withdrawal due to drought, see Chapter 8.
Space and water heating in California is dominated by energy devices, such as furnaces,
consuming natural gas. Observations of heating degree days 444 in California in the last few
decades show a declining trend. For example, as depicted in Figure 67, the decline of
heating degree days is about 15 percent from 1960 to 2014 in the San Joaquin Valley, which
should have decreased the amount of natural gas consumed for space heating in a more or
less proportional way. Since the consumption of natural gas in weather-dependent energy
services for space and water represent about 88 percent 445 of the natural gas consumed in the
residential sector, the number of heating degree days and cooling degree days are closely
linked to energy demand and, consequently, energy savings. For example, a decrease in
heating degree days can result in substantial energy savings. The overall downward trend
in heating degree days, at least in the Central Valley, seems to be linked to reported
reductions of Tule fog in the same region. 446
443 Baum, R.L., D.L. Galloway, , and E.L. Harp. 2008. Landslide and Land Subsidence Hazards to
Pipelines: U.S. Geological Survey Open-File Report 2008-1164, p. 192.
444 Heating degree days is parameter that is designed to reflect the demand for energy needed to heat a
home or building. Heating degree days are calculated using ambient air temperatures and a base
temperature (for example, 65 degrees) below which it is assumed that space heating is needed.
Similarly, cooling degree days are designed to reflect the demand for energy needed to cool a home or
building.
445 California Historical Residential Natural Gas Use. 2015.
http://www.energyalmanac.ca.gov/naturalgas/residential_use.html.
446 Baldocchi, Dennis, Eric Waller. 2014. “Winter Fog Is Decreasing in the Fruit Growing Region of
the Central Valley of California.” Geophys. Res. Lett. 41:2014GL060018+.
280

Figure 67: Changes in Heating Degree Days in the NOAA Sacramento and San Joaquin
Climatic Zones
Source: NOAA
Climate Impacts on Petroleum Transportation Fuels
The vulnerability of oil refineries to climate change is an understudied area of research. 447
Yet given the proximity of most of California’s refineries to the ocean, they may be at risk of
saltwater intrusion and damage from sea-level rise and storm surges. 448 Refineries are also
major consumers of electricity. This means that the climate vulnerabilities of some electricity
generation stations would be shared by those refineries. Water availability is also a concern
for oil refineries. Refineries in California use a great deal of water to create steam used in
industrial processes. Weather-related extreme events linked to climate change, such as
prolonged droughts, could alter the average quantity and seasonal deposition of snowfall in
the Sierra Nevada watershed, significantly reducing the volume of seasonal runoff and
447 More information about GHG emissions from the petroleum sector is also needed to better
understand climate impacts from this sector. Chapter 7, Changing Trends in California’s Sources of
Crude Oil puts forward a recommendation to address this need.
448 Perez, Pat. 2009. Potential Impacts of Climate Change on California’s Energy Infrastructure and
Identification of Adaptation Measures. California Energy Commission. Publication Number: CEC-150-
2009-001.
281

water availability in California. Decreased water supplies tend to give rise to competition
among all uses, with the possibility of decreased availability for energy. To the extent that
potable water sources are no longer available for use by industry (including refineries),
other potential sources would have to be pursued, along with strategies and technologies
aimed at reducing water intensity at refineries. For more information on how the drought is
impacting California’s energy system, see Chapter 8.
Oil pipelines may also be sensitive to sea-level rise at ports. California’s petroleum and
transportation fuels infrastructure normally involves the movement of raw and finished
transportation fuel products via marine vessels and a network of pipelines that connect
wharves to refineries, storage tank farms, distribution terminals, and associated structures.
The wharf structures used to unload and load marine vessels are designed to accommodate
a wide range of tidal variation daily and annually. An increase in the mean average sea
level, however, would significantly raise the maximum high-tide levels, such that the
existing wharf system used for moving petroleum products and other waterborne
commerce might need to be adjusted.
There are no studies available on the climate impacts on the transportation fuel supply
network in California (for example, oil refineries and oil pipelines), although the California
Department of Transportation has funded and continues to support studies on the
vulnerability of the transportation network in California. The Energy Commission plans to
help fill this gap with a study that will also be part of California’s fourth climate change
assessment with a focus on the transportation fuels infrastructure. Risks may potentially
include those from sea-level rise, inland flooding, landslides, and wildfires; but the severity
of those risks and their geographic distribution have yet to be determined. For example, it is
possible that some refineries may be well protected by levees or are situated outside areas
that are most at risk of inundation during extreme weather events.
Initial Integration of Mitigation and Adaptation
The elements of California’s energy system do not stand independent of one another. They
are interconnected with broader policy and socioeconomic changes and biogeochemical
changes from altered climate. California’s energy system is not independent from those of
other western states. Yet thus far, energy scenarios developed for California have separated
elements; they have tended to assume either a static energy infrastructure and compared
that against future climate change, or have examined evolving energy infrastructure in light
of policy goals, but not taken into account climate change. In practice, both California’s
climate and energy system are changing very rapidly. Future studies for California must
consider both simultaneously. In addition, a rapid decarbonization of the energy system
(mitigation) represents an opportunity for the scientific community to develop information
that could be used to guide this development to create an energy system that is less
vulnerable (adaptation) to climate impacts.
282

The California Natural Resources Agency is leading the preparation of the next California
climate assessment. It published a draft scope of work 449 late in 2014 identifying the research
projects that it plans to support, covering non-energy research such as the identification of
adaptation options for the agricultural sector and how increased frequency and intensity of
wildfires may affect insurance rates. The Energy Commission, via its Electric Program
Investment Charge (EPIC) and Natural Gas Research and Development Programs, is
supporting energy-related research for the climate assessment. The California Natural
Resources Agency scope of work describes how the energy and non-energy research
projects are being coordinated and integrated. For example, all the research teams will use a
common set of climate, sea-level rise, and socioeconomic scenarios to ease the integration of
results.
Multiple studies and new areas of research have been identified for the energy sector, such
as the evaluation of risks to electricity distribution networks from wildfires. Prior work on
wildfire risk done for the 2012 California climate assessment addressed only the risk to
transmission lines. Since most of the grid disruptions from wildfires are due to their effects
on the distribution system, new research is needed. Another study will identify potential
barriers to the timely adoption of attractive adaptation measures such as regulatory, legal,
and institutional constraints. In-depth regional studies for the electricity and natural gas
systems are also planned. Prior assessments identified only exposure of energy facilities to
100-year storms on top of sea-level rise to identify power plant, transformers, and other
energy facilities potentially at risk; however, the inundation maps used for these studies did
not consider the evolution of the California shoreline with sea-level rise and the protecting
effect afforded by levees and armoring that may be protecting these energy plants. The new
studies will address these issues. The California Natural Resources Agency will fund the
application of an advanced coastal evolution model that takes into account the movement of
sand with currents, wave action during storms, and erosion of cliffs, among other important
physical factors. The Energy Commission will use this information to produce more realistic
estimates of the impacts to energy facilities.
For the first time the Energy Commission will be able to support studies looking at the
vulnerability of oil refineries, oil pipelines, and other units that are part of the network
supplying transportation fuels such as gasoline and diesel. The Energy Commission is
promoting a joint effort by three major research groups (LBNL along with UC Berkeley, UC
Irvine, and E3) to develop more realistic energy scenarios for California that simultaneously
consider rapid changes to energy infrastructure, changing climate, and climate impacts to
energy infrastructure. Final results of these coordinated scenarios will be released in 2018.
The combined work represents the next generation of scenarios for California, being
produced with an eye toward making the research products that are feasible and useable for
decision makers and energy stakeholders. The scenarios will build off prior work and
449 California Natural Resources Agency. 2015. California’s Fourth Climate Change Assessment.
283

include several common elements; for example, they will use common climate and sea-level
rise scenarios that are under development for the fourth California climate assessment. The
energy scenarios will also be intercomparable. To estimate the robustness of their results,
the scenarios will also use different models of the electricity system.
The Energy Commission is also supporting other related studies that are expected to be winwin
opportunities 450 under current and future climatic conditions. It is funding the
development of methods to improve seasonal (a few months in advance) and decadal (next
20 years) forecasts in a probabilistic framework. This work will be conducted in close
coordination with Energy Commission demand forecast staff, the California ISO, and
energy utilities to make sure the results are tailored to their needs and provided in a format
that they can use. Prior studies supported by the Energy Commission and others show that
this type of work will also be useful to adapt planning and decision-making to a changing
climate. A prior research project using probabilistic hydrologic climate projections and a
modern decision support system was demonstrated to outperform current management
practices at five of the major water reservoirs in Northern California by providing more
water for consumptive uses while increasing electricity generation. 451 The same system was
shown to be extremely helpful in ameliorating climate impacts, especially under dry climate
conditions. 452
Finally, the Energy Commission developed Cal-Adapt, 453 a web-based interactive platform
that enables users to visualize local and regional climate change impacts associated with
high- and low-GHG emission trajectories based on current peer-reviewed scientific research.
Users can also download datasets and, pending upcoming release of version 2.0 that will
include an Applications Programming Interface, develop custom tools to manipulate data
that lends itself to support specific decision-making and planning processes. Cal-Adapt
provides access to regionally downscaled climate scenarios developed through Energy
Commission funding, as well as “secondary” scenarios (such as hydrological modeling or
wildfire risks) that are derived from downscaled climate scenarios. These scenarios will be
used for original research and as a basis for California’s fourth climate change assessment.
450 “Win-win” opportunities are also described as no regrets strategies. These are strategies that result
in benefits even without the consideration to climate benefits.
451 Georgakakos, K. P., Graham, N. E., Carpenter, T. M., and Yao, H. 2005. “Integrating
Climate‐Hydrology Forecasts and Multi‐Objective Reservoir Management for Northern
California.” Eos, Transactions American Geophysical Union. AGU 86:122-127.
452 Georgakakos, A.P., H. Y., M. Kistenmacher, K.P. Georgakakos, N.E. Graham, F.‐Y. Cheng, C.
Spencer, and E. Shamir. 2011b. “Value of Adaptive Water Resources Management in Northern
California Under Climatic Variability and Change.” Advanced Reservoir Management and Engineering,
Elsevier, 13.
453 http://cal-adapt.org/.
284

The scenarios will ensure cross-sectoral coherence, providing grounds for integration of
studies across sectors, as well as between mitigation and adaptation.
Climate Change and Air Quality Considerations
Reducing fossil fuel consumption to reduce CO2 emissions also decreases emissions of
traditional air pollutants such as oxide of nitrogen (NOx), which are the precursors to ozone.
However, as shown in the figure below, the major sources of NOx are not necessarily the
main sources of carbon dioxide. Figure 68 shows the percentage statewide contribution of
different sources to total NOx and CO2, as reported by the Air Resources Board. Further,
ambient air quality standards are assessed for individual air basins—where emissions can
become sufficiently concentrated to create health hazards—while GHG emissions have
global, not local, air quality consequences. Therefore, as suggested by some, 454 in the next
decade or two reductions of CO2 and other GHG emissions are not necessarily accompanied
by proportional improvements in ambient air quality in the most impacted air basins.
Compliance with ozone ambient air quality standard in the South Coast and San Joaquin
Air Basins would require NOx emission reductions of about 90 percent below current levels.
An analysis by the South Coast Air Quality Management District shows that although NOx
emissions will be significantly reduced as result of policies to meet the 2030 GHG reduction
goal, the reductions are not expected to be enough to meet 2023 and 2031 ozone attainment
standards. The analysis shows that special energy strategies will be needed in the South
Coast to meet air quality standards. 455
454 Tarroja. B. Transition to a Low-Carbon Economy: Air Quality Consideration. June 24, 2015, IEPR
workshop.
455 SCAQMD, Draft Final Energy Outlook Whitepaper, October 2015.
http://www.aqmd.gov/home/about/groups-committees/aqmp-advisory-group/2016-aqmp-whitepapers
285

Figure 68: Percentage Contribution of NO x and CO 2 Emissions by Different Sources
Data Source: California Air Resources Board.
The Energy Commission and others are funding research to substantially lower NOx
emissions from heavy-duty trucks. California’s transportation sector—particularly heavyduty
vehicles, such as transit buses, refuse trucks, and parcel delivery vehicles operating in
densely populated neighborhoods—is one of the primary sources of harmful emissions that
contribute to air quality issues, preventing several California regions from meeting federal
ambient ozone standards. Ongoing efforts to reduce emissions in heavy-duty vehicles has
been a priority for the Energy Commission’s Research and Development Natural Gas
Program, beginning with the development of advanced heavy-duty natural gas engines that
easily meet the ARB 2010 Heavy-Duty Emission Standards. Following the successful
development of these engines, efforts have been made to advance engine designs to increase
performance, improve efficiency, and reduce emissions including NOx and other harmful
emissions. More recent research projects include development of natural gas engines and
systems with electric hybridization strategies, cylinder deactivation methods, and cuttingedge
advanced ignition systems, with the goals of driving to near-zero NOx emissions or 90
percent below ARB 2010 Emission Standards. Continued advancement of near-zero natural
gas vehicle technologies will support efforts to improve air quality in California and
especially in disadvantaged communities where people are more reliant on public
transportation or located near high-traffic areas.
286

U.S. Department of Energy, Partnership for Energy Sector Climate
Resilience
In addition to the resources provided at the state level, the U.S. Department of Energy
recently launched a program to partner with local energy utilities to promote energy
infrastructure that is resilient to climate impacts and extreme weather events. The
foundation of these partnerships is an agreement on the part of utilities to identify their
climate vulnerabilities; develop, prioritize, and pursue strategies for resilience; and measure
and report the results of those strategies. In return, the U.S. Department of Energy provides
utilities with technical assistance, access to relevant climate data, assistance with the
development of climate decision-making tools, and national recognition for partner utilities.
In California Pacific Gas and Electric, San Diego Gas and Electric, Southern California
Edison, and Sacramento Municipal Utility District have signed up as partners.
Future Research Directions
The prior section described ongoing and planned work that will start late in 2015 and early
in 2016, which may take two to three years to complete. This section describes, at a
conceptual level, future energy-related climate change research that the Energy Commission
will support under its EPIC and PIER Natural Gas Research and Development programs.
No ongoing research funding is available to support similar studies for the petroleum
sector, including the network that provides petroleum-based transportation fuels. For this
reason, the following section does not address climate-related research needs for the
petroleum sector.
Climate and Sea-Level Rise Scenarios
California is a national leader in developing climate and sea level rise scenarios that are
useful not only for research, but relevant for long-term planning. 456 A new downscaling
technique developed by Scripps, with funding from the Energy Commission, is being
adopted at the national level. 457 However, more work is still needed, as described in the
Climate Change Research Plan for California. 458 For example, current research products are not
at a stage of development to indicate how climate change may impact renewable sources of
energy.
456 Cayan, Daniel R, Amy L. Luers, Guido Franco, Michael Hanemann, Bart Croes, and Edward
Vine. 2008. “Overview of the California Climate Change Scenarios Project.” Climatic Change. 87:1-6.
457 Franco, Guido. 2015. Climate Scenarios for the California Energy System: Expected Outcomes.
Presentation.
458 Climate Action Team. 2015. Climate Change Research Plan for California.
287

Improve Methods to Estimate GHG Emissions from the Energy System
The Energy Commission supported the first national pilot program measuring ambient
GHG concentrations using tall communication towers. 459 These measurements
demonstrated that actual emissions of methane and nitrous oxide are most likely severely
underestimated in California. 460, 461, 462 This conclusion has initiated a host of new
measurement programs in California. The Energy Commission plans to continue supporting
research that attempts to better quantify energy-related emissions in California. The
substantial research program measuring methane emissions from the natural gas system
will continue focusing on identifying gross emitters and options to reduce emissions. This
work is and will continue to be conducted in coordination with the ARB and other entities.
Simultaneous Consideration of Mitigation and Adaptation for the Energy System
There are multiple ways to improve this area of work. For example, the Energy Commission
has plans to support more granular technical research studies that address issues such as the
consideration of individual and institutional behavior in the adoption of
mitigation/adaptation measures for the energy system. An exploratory study conducted by
LBNL for the Energy Commission found good opportunities for nontechnical measures to
address mitigation needs in California. 463 Physical assessments of renewable energy
potential that have been conducted to date 464 have not considered factors such as water
availability, effects of climate change, permitting issues, and other factors that may render
prior resource assessments unrealistic. More realistic resource assessments are greatly
needed. Work completed for the Desert Renewable Energy Conservation Plan (discussed
further in Chapter 3) applied some constraints to better estimate the potential for solar and
wind in the southeast desert region of California. 465 For example, planners accounted for the
anticipated constraints to siting and developing renewable energy in specific regions, such
459 Nature. 2007. Greenhouse-Gas Sensors Tower Over California. Nature 449, 960 (270).
460 Zhao, C., A. E. Andrews, L. Bianco, J. Eluszkiewicz, A. Hirsch, C. MacDonald, T. Nehrkorn, and
M. L. Fischer. 2009. “Atmospheric Inverse Estimates of Methane Emissions From Central California. J.
Geophys. Res., 114, D16302, doi:10.1029/2008JD011671.
461 Jeong, S., C. Zhao, A.E. Andrews, L. Bianco, J.M. Wilczak, M.L. Fischer. 2012. Seasonal Variation of
CH[4] Emissions from Central California. J. Geophys. Res., Vol. 117, No. D11, D11306.
462 Ibid.
463 Mills, Andrew, Ryan Wiser. 2014. Strategies for Mitigating the Reduction in Economic Value of
Variable Generation With Increasing Penetration Levels.
464 Hernandez, Rebecca R., Madison K. Hoffacker, Christopher B. Field. 2015. “Efficient Use of Land
to Meet Sustainable Energy Needs.” Nature Clim. Change 5, no. 4: 353–58.
465
http://www.drecp.org/draftdrecp/files/Appendix_F_Megawatt_Distribution/Appendix_F1_Methods_
for_MW_Distribution.pdf.
288

as land-use constraints, feasibility of added transmission capacity, and the extent to which
land is parcelized (for example, with multiple small privately owned parcels) and therefore
viewed as more difficult to develop. The value of lands for biological conservation also
factored in to limiting the technological potential for renewable energy. The primary
constraint in the plan alternatives was areas needed for conservation of special-status
species now and areas for their potential movement as an adaptation response to future
climate change.
Future research developing new long-term energy scenarios for California will be used to
integrate the technology information generated by the EPIC and PIER Natural Gas Research
and Development programs in an overall picture of the energy system. This could show
what technology development paths are the most promising options to achieve 80 percent
GHG reductions by 2050.
Finally, the research on long-term energy scenarios must consider other policy goals such as
the ones outlined in Executive Order B-32-15, 466 requiring the development of an integrated
action plan by July 2016 that establishes clear targets to improve freight efficiency,
transitions to zero-emission technologies, and increases the competitiveness of California's
freight system.
Local and Regional Studies
Local and regional mitigation-adaptation studies can provide high-level detail that can
make these studies more realistic and informative for decision-making than large-scale
studies. Close cooperation with energy utilities is essential, however, and may include
sharing sensitive information. A framework must be developed to allow data sharing with
the research community while protecting the economic and legal rights of the utilities and
their customers.
Regional studies will also include the development of models that link higher-elevation
hydropower units with rim or low-elevation reservoirs. This is needed to better understand
the challenges posed to the system by changes in precipitation patterns while exploring the
potential opportunities identified as result of this integrated view to hydropower
generation.
Recommendations
California has been an early leader on innovative climate research programs that connect
the changing climate to the state’s energy system. To create actionable science and increase
the resiliency of the energy system, this work must continue and be enhanced to more
effectively address the needs of the rest of this century.
466 http://www.gov.ca.gov/news.php?id=19046.
289

• Expand transparency of utility energy data to better inform analyses of the
impacts of climate change on California’s energy system. The California Public
Utilities Commission (CPUC) should build on its prior orders to expand
transparency and data-sharing on the part of utilities, and develop a framework for
closer research coordination between energy utilities and local and regional actors.
Specifically, the CPUC should make data from utilities more reliably accessible to
researchers. Coordination of this kind has the potential to ensure research is
actionable and informs the actual needs of both utilities and stakeholders. This is
needed for a stronger, more unified effort to make the state’s energy system and
communities more resilient to climate change impacts.
• Oil industry should study climate impacts. The oil industry should study the
impacts of climate change, including sea level rise, wildfire, and drought, on
extraction, refinery, storage, transport, and distribution infrastructure. This is an
understudied area that requires more research to inform adaptation planning.
• Harmonize climate studies for the energy sector using the Energy Commission’s
climate and sea level rise scenarios. To easily compare studies on climate impacts
and adaptation studies for the energy sector, private and public energy utilities and
other entities should use the climate and sea-level rise scenarios being developed for
the energy part of the next California’s Fourth Climate Change Assessment.
290

Acronyms
AAEE — additional achievable energy efficiency
AB — Assembly Bill
AEO
ALJ
—
—
Annual Energy Outlook
Administrative Law Judge
AQIP — Air Quality Improvement Program
ARB — California Air Resources Board
ARFVTP — Alternative and Renewable Fuel and Vehicle Technology Program
BEES — Building Energy Efficiency Standards
BLM — Bureau of Land Management
BPD — barrels per day
CAEATFA — California Alternative Energy and Advanced Transportation Financing
Authority
CAFE — Corporate Average Fuel Economy
CalHSR — California High-Speed Rail Authority
California ISO — California Independent System Operator
CBR — crude-by-rail
CCCSIP — Central Coastal California Seismic Imaging Project
CCS — Carbon capture and storage
CHP — combined heat and power
CMUA — California Municipal Utilities Association
CO2 — carbon dioxide
CPCN — certificate of public convenience and necessity
CPUC — California Public Utilities Commission
CSD — Department of Community Services and Development
DATC — Duke-American Transmission Company
DC — direct current
DCISC — Diablo Canyon Independent Safety Committee
DDE — double design earthquake
DE — design earthquake
DG — renewable distributed generation
DOE — Department of Energy
DRECP — Desert Renewable Energy Conservation Plan
E85 — blend of 85 percent ethanol and 15 percent gasoline
ECAA — Energy Conservation Assistance Act
ECAA-Ed — Energy Conservation Assistance Act- Educational Subaccount
EEP — energy expenditure plan
291

EIA
EIM
—
—
United States Energy Information Administration
energy imbalance market
EIS — environmental impact statement
EM&V — evaluation, measurement, and verification
EPIC — Electric Program Investment Charge
FAA — Federal Aviation Administration
FERC — Federal Energy Regulatory Commission
GGRF — Greenhouse Gas Reduction Fund
GHG — greenhouse gas
GIS — geographic information system
gpf — gallons-per-flush
gpm — gallons-per-minute
GW — gigawatt
GWh — gigawatt hours
HE — Hosgri Evaluation
HERS — Home Energy Rating System
HI-STORM — Holtec International Storage Module
HSR — high-speed rail
HHFT — high hazard flammable train
HVAC
HVDC
IEPR
IID
—
—
—
—
heating, ventilation, and air conditioning
high-voltage direct current
Integrated Energy Policy Report
Imperial Irrigation District
IOU — investor-owned utility
IPCC — Intergovernmental Panel on Climate Change
IPRP
kV
—
—
Diablo Canyon Independent Peer Review Panel
kilovolt
LADWP — Los Angeles Department of Water and Power
LBNL — Lawrence Berkeley National Laboratory
LCFS
LCR
—
—
Low Carbon Fuel Standard
local capacity requirement
LDV — light-duty vehicle
LEA — local education agencies
LGIA — Large Generator Interconnection Agreement
LLC — limited liability corporation
LNG — liquefied natural gas
LTPP — Long Term Procurement Plan
LTSP — Long Term Seismic Program
292

MDV/HDV — medium- and heavy-duty vehicles
MMTCO2E — million metric tons of carbon dioxide equivalent
MOU — Memorandum of Understanding
MW
NAMGas
—
—
megawatt(s)
North American Market Gas Trade
NCPA — Northern California Power Authority
NHTSA — National Highway Traffic and Safety Administration
NOx — oxides of nitrogen
NRC — Nuclear Regulatory Commission
NREL — National Renewable Energy Laboratory
NSHP — New Solar Homes Partnership
OII — Order Instituting Informational
OPEC — Organization of Petroleum Exporting Countries
OSPR — Office of Spill Prevention and Response
OTC
PACE
—
—
once-through cooling
Property Assessed Clean Energy
PADD — Petroleum Administration for Defense District
PEA — Proponent’s Environmental Assessment
PG&E — Pacific Gas and Electric Company
PHEV — plug-in hybrid electric vehicle
PIER — Public Interest Energy Research
PM — particulate matter
POU — publicly owned utility
PPA — power purchase agreement
PSEP — pipeline safety enhancement plan
PSHA — probabilistic seismic hazard analysis
PV — photovoltaic
QF — qualifying facility
R&D — research and development
RAC — refiner acquisition cost
REAT — Renewable Energy Action Team
RECPG — Renewable Energy and Conservation Planning Grants
RETI — Renewable Energy Transmission Initiative
RPS — Renewables Portfolio Standard
San Onofre — San Onofre Nuclear Generating Station
SB — Senate Bill
SCE — Southern California Edison Company
SCPPA — Southern California Public Power Authority
293

Scripps — Scripps Institution of Oceanography
SDG&E — San Diego Gas & Electric
SEIR — supplemental environmental impact report
SEIS — supplemental environmental impact statement
SMUD
— Sacramento Municipal Utility District
SoCalGas
SR
SunZia
SWIP
—
—
—
—
Southern California Gas Company
State Route
SunZia Southwest Transmission Project
Southwest Intertie Project
SWRCB — State Water Resources Control Board
TDV — time dependent valuation
TEPPC — Transmission Expansion Planning Policy Committee
TPP — Transmission Planning Process
TRTP
TWE
—
—
Tehachapi Renewable Transmission Project
TransWest Express Transmission Project
U.S. EPA — United States Environmental Protection Agency
USFS — United States Forest Service
VAR — Volt-ampere reactive
VMT — vehicle miles traveled
WECC
Western
—
—
Western Electricity Coordinating Council
Western Area Power Administration
WET — Water Energy Technology
ZEV
— zero-emission vehicle
ZNE
— zero-net energy
294

APPENDIX A:
Renewable Energy Action Plan Progress
The Energy Commission’s 2012 Integrated Energy Policy Report Update included a Renewable
Action Plan for increasing renewable development in California. This appendix summarizes
progress made on the action items identified in the plan since adoption of the plan in early
2013. 467
Strategy 1: Identify Priority Areas for Renewable Development
An important lesson learned over the last decade when it comes to renewable development
is that project location is crucial. The site of a utility-scale or distributed renewable project
affects how quickly a project can be permitted and interconnected, which in turn affects the
overall cost of the project. The Renewable Action Plan recommended that priority areas for
renewable development should have high levels of renewable resources, be located where
development will have the least environmental impact, and be close to planned or existing
transmission or distribution infrastructure.
Recommendation 1: Incorporate Distributed Renewable Energy Development Zones
Into Local Planning Processes
With increasing amounts of renewable distributed generation (DG) being installed in
California, the first recommendation under Strategy 1 was to incorporate renewable DG into
local planning processes. Local governments typically have permitting authority for many
types of renewable projects, but many local governments do not have the data and resources
to include renewable development in their land-use plans.
Since adoption of the Renewable Action Plan, several initiatives have been launched to
identify preferred areas for renewable DG development.
• Assembly Bill 327 (Perea, Chapter 611, Statutes of 2013) requires investor-owned utilities
(IOUs) to submit distribution resource plans to the California Public Utilities
Commission (CPUC) that identify the best locations for renewable DG and other
distributed energy resources from a utility perspective. This will help developers
identify the higher value locations for these projects. The plans were filed on July 1,
2015, and are available for public review. 468
467 More detail on recommendations and action items is available in the 2012 Integrated Energy Policy
Report Update, Chapter 5, Renewable Action Plan, http://www.energy.ca.gov/2012_energypolicy/.
468 California Public Utilities Commission, Distribution Resources Plan Applications (filed July 1,
2015), http://www.cpuc.ca.gov/PUC/energy/drp/. Information on the requirements for the plans is
available at: http://www.cpuc.ca.gov/NR/rdonlyres/9F82A335-B13A-4F68-A5DE-
3D4229F8A5E6/0/146374514finalacr.pdf.
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• The California Independent System Operator (California ISO) has begun an annual
process to identify available deliverability for DG projects connected to utility
distribution systems. Available deliverability indicates where existing transmission
capacity is available to support deliverability status assignments. 469
• As part of the CPUC’s Renewable Auction Mechanism, IOUs are posting maps to help
project developers determine potential project sites. The maps show areas on the utility
system where capacity for DG projects may be available, which helps developers
determine how expensive a project might be and how long it might take to get
interconnected. 470
• To help bridge the gap between utility planning and local land-use planning, the Energy
Commission is partnering with Southern California Edison on a distributed energy
resource pilot study in the San Joaquin Valley to explore the potential of relying on
distributed resources to meet forecasted electricity system needs. Most distributed
resource growth to date has occurred largely as the result of random customer
investment decisions, but going forward investments need to be planned and
coordinated to provide the most value. This can be accomplished in part through closer
coordination between utility and local planning processes to direct investments to
locations that benefit electric system operations, provide value to customers, and
minimize adverse environmental impacts.
• The Energy Commission has published three reports that have identified locationspecific
value for renewable projects, particularly distributed generation projects:
Identification of Low-Impact Interconnection Sites for Wholesale Distributed Photovoltaic
Generation Using Energynet® Power System Simulation; 471 Integrated Transmission and
469 California Independent System Operator, Resource Adequacy Deliverability for Distributed
Generation, 2014-2015 DG Deliverability Assessment Results, February 11, 2015,
http://www.caiso.com/Documents/2015DeliverabilityforDistributedGenerationStudyResultsReport.p
df.
470 Pacific Gas and Electric:
www.pge.com/en/b2b/energysupply/wholesaleelectricsuppliersolicitation/PVRFO/pvmap/index.pag
e; Southern California Edison: www.sce.com/ram; San Diego Gas & Electric:
http://www.sdge.com/generation-interconnections/interconnection-information-and-map.
471 California Energy Commission consultant report, New Power Technologies, December 2011,
http://www.energy.ca.gov/2011publications/CEC-200-2011-014/CEC-200-2011-014.pdf.
A-2

Distribution Model for Assessment of Distributed Wholesale Photovoltaic Generation; 472 and
Distributed Generation Integration Cost Study – Analytical Framework. 473
Recommendation 2: Identify Renewable Energy Development Zones
The second recommendation for identifying high-priority areas for renewable development
was to identify renewable energy development zones for all sizes and technology types of
renewable resources, with the goal of using the existing built environment first, followed by
areas with minimal environmental or habitat value, such as marginal or impaired
agricultural lands.
This recommendation is intended to build on experience and science gained through the
Desert Renewable Energy Conservation Plan (DRECP) to identify high-priority areas for
renewable energy development throughout the state.
The most significant progress on this recommendation has been the success of the DRECP
effort and the unprecedented coordination among local governments, federal and state
agencies, utilities, and various stakeholders to identify areas where renewable development
can occur with fewer environmental impacts, as well as sensitive areas that should be
protected for conservation. The effort focused on more than 22.5 million acres in the
California Deserts, with a draft plan and programmatic environmental analysis released in
September 2014. Based on comments received on the draft plan, in March 2015 the Bureau of
Land Management, the U.S. Fish and Wildlife Service, the Energy Commission, and the
California Department of Fish and Wildlife announced a phased approach to finalize
development of the DRECP, starting with completion of the BLM Land Use Plan Amendment,
which designates development focus areas and conservation areas on public lands. This
phased approach also allows time for the counties to complete their Renewable Energy and
Conservation Planning Grant projects, for agencies to continue to collaborate with the
counties to address local needs in the planning process, and to ensure better alignment of
local, state, and federal goals.
Other actions to support identifying renewable energy development zones include:
• In 2013 and 2014, the Energy Commission provided more than $5 million in grants to
local governments through the Renewable Energy and Conservation Planning Grants
Program to develop or amend rules and policies that “facilitate the development of
eligible renewable energy resources and the associated electric transmission facilities,
and the processing of permits for eligible renewable energy resources.” 474 Counties that
472 California Energy Commission consultant report, New Power Technologies, April 2013,
http://www.energy.ca.gov/2013publications/CEC-200-2013-003/CEC-200-2013-003.pdf.
473 California Energy Commission consultant report, Navigant Consulting, Inc., September 2014,
http://www.energy.ca.gov/2013publications/CEC-200-2013-007/CEC-200-2013-007-REV.pdf.
474 California Energy Commission, http://www.energy.ca.gov/renewables/planning_grants/.
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eceived awards include Imperial, Inyo, Los Angeles, Riverside, San Bernardino, and
San Luis Obispo. Grant projects from the 2013 solicitation were completed in 2015, and
grants from the 2014 solicitation will be completed in early 2016.
• The Energy Commission is providing technical expertise for the San Joaquin Valley
Solar convening. The San Joaquin Solar convening is a stakeholder-led effort to identify
least-conflict lands in the San Joaquin Valley that are suitable for renewable energy
development.
• The Energy Commission, in collaboration with Conservation Biology Institute, has
developed several geo-spatial tools, including the DRECP Data Basin Gateway, DRECP
Climate Console, and the Renewable Energy Generation Scenario Builder, to integrate
multiple layers of scientific data and develop transparent renewable and conservation
planning scenarios.
• On July 31, Energy Commission Chair Weisenmiller and CPUC President Picker sent a
letter to California ISO President and CEO Berberich announcing the establishment of
the Renewable Energy Transmission Initiative 2.0. This initiative will identify the
relative renewable energy potential associated with various locations of the state and the
associated transmission infrastructure. The stakeholder-driven process will commence
this year with the goal to send policy recommendations for the 2030 renewables
portfolios to the California ISO in 2016.
Recommendation 3: Conduct 2030 Analysis
This recommendation targeted the need for planning efforts beyond 2020 given interest in
higher renewable targets and uncertainty about continued operation of the state’s nuclear
plants. Analysis of the electricity sector in 2030 and beyond is taking place in several
forums.
• The “Pathways Study,” commissioned by the energy agencies and the Air Resources
Board was completed in January 2015, with updated materials made available in April
2015. It included multiple scenarios to evaluate a range of possible 2030 targets on the
way to meeting California’s 2050 greenhouse gas (GHG) emission reduction target. 475
The study found that it is possible to reduce GHG emissions by 26 percent to 38 percent
from 1990 levels by 2030 through increased energy efficiency, development of renewable
energy, electrification of buildings and vehicles, and reductions in the carbon content of
liquid fuels.
475 Energy+Environmental Economics (E3), 2015, Summary of the California State Agencies’
PATHWAYS Project: Long-term Greenhouse Gas Reduction Scenarios,
https://ethree.com/public_projects/energy_principals_study.php.
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• The California Independent System Operator’s (California ISO) 2015-2016 Transmission
Planning Process is examining several renewable portfolios for 2030, including two that
evaluate a 50 percent RPS. (See Recommendation 11 for more information.)
• The DRECP is continuing to look at future renewable development scenarios, including
an assessment of potential central-station renewable project development in 2040 in the
DRECP area. 476
Recommendation 4: Continue Development of Renewable Energy on Government
Property
In 2011, the Energy Commission’s Developing Renewable Generation on State Property report
recommended a goal of 2,500 MW of renewables on state properties by 2020, with interim
targets of 833 MW by 2015 and 1,666 MW by 2018. 477 The target was based on an inventory
of technical potential at state buildings, properties, and lands with potential for wholesale
generation.
Progress on this recommendation has been slow. According to the Department of General
Services’ Renewable Energy Directory, there are 43 MW of renewable projects installed on
state properties, with another 8 MW planned, far short of the 833 MW interim goal for 2015.
In addition, the majority of installed and planned projects are less than 1 MW in size,
indicating more focus may be needed on promoting larger installations going forward to
achieve the interim and long-term targets. In support of this effort, on October 1, 2015, the
California State Lands Commission and the Bureau of Land Management announced a
historic agreement to pursue an exchange of state lands with federal lands. This State Land
Exchange will advance state and federal conservation and energy strategies of the DRECP
by consolidating federal lands within the National Conservation Lands area and providing
the state with lands that have operational, or potential for, renewable energy facilities.
Strategy 2: Evaluate Costs and Benefits of Renewable Projects
Strategy 2 focused on the importance of broadening the assessment of renewable costs
beyond simple technology costs to include things like renewable integration, permitting,
and interconnection, while also considering the system and nonenergy benefits of renewable
resources, particularly those that improve grid stability and reduce environmental and
public health costs.
476 California Energy Commission, http://www.drecp.org/.
477 California Energy Commission, Developing Renewable Energy on State Property, April 2011,
http://www.energy.ca.gov/2011publications/CEC-150-2011-001/CEC-150-2011-001.pdf.
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Recommendation 5: Modify Procurement Practices to Develop a Higher Value
Portfolio
There has been some progress on this recommendation relative to procurement by publicly
owned utilities (POUs) as a result of requirements for POUs to adopt and implement
renewable resource procurement plans for the RPS and procure enough eligible resources to
meet their RPS targets. Energy Commission staff also found that POUs have generally
improved their planning for, and acquisition of, renewable generation.
There is less progress on other actions identified under Recommendation 5, particularly that
RPS procurement decisions by the IOUs and POUs should be based on a wider variety of
information, such as integration costs and benefits, interconnection costs, ability to provide
reliability services, and geographic and technology diversity.
The CPUC did evaluate RPS procurement reform starting in October 2012, with a November
2014 decision released on the 2014 RPS procurement plans that adopted findings related to
certain elements of RPS procurement. 478 While the decision adopted an interim renewable
integration cost adder, it did not fully address the expanded suite of renewable energy
benefits identified in the Renewable Action Plan. The CPUC intends to complete work on a
final method for calculating a renewable integration cost adder as part of the RPS
continuation rulemaking opened in February 2015. 479
Recommendation 6: Revise Residential Electricity Rate Structures
The Renewable Action Plan supported a revised electricity rate design that fairly spreads
new costs, including infrastructure costs, among all customers while maintaining an
incentive for the efficient use of electricity. It identified residential rate design as the first
priority but noted that commercial and industrial rate design may also need to be
considered in the future, and expressed support for the CPUC’s proceeding on residential
rate structures.
In April 2015, the CPUC issued a proposed decision in the residential rate reform
proceeding that lays out a path to transition customers to fairer, more economically efficient
rates. 480 Implementation is expected to begin in 2019, informed by pilot studies on time-of-
478 California Public Utilities Commission, D. 14-11-042, Decision Conditionally Accepting 2014
Renewables Portfolio Standard Procurement Plans and an Off-Year Supplement to 2013 Integrated Resource
Plan, November 20, 2014,
http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M143/K313/143313500.PDF.
479 California Public Utilities Commission, R.15-02-020, Scoping Memo and Ruling of Assigned
Commissioner, May 22, 2015,
http://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M151/K862/151862437.PDF.
480 California Public Utilities Commission, R.12-06-013, Decision on Residential Rate Reform for Pacific
Gas and Electric Company, Southern California Edison Company, and San Diego Gas & Electric Company and
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use rate design. The goal is to provide transparent, cost-based rates that will encourage
residential customers to shift their energy use to certain times of day to support a cleaner,
more reliable grid and reduce total electricity costs for all customers.
To achieve this goal, the IOUs will begin by:
• Continuing to consolidate and narrow the existing energy usage tiers so that electricity
prices are more understandable and less distorted.
• Implementing improved tools to compare bills and a special outreach program to
educate lower-tier customers on low- or no-cost ways to save energy.
• Implementing a minimum bill to ensure that all customers connected to the system
contribute some amount toward system costs.
• Designing time-of-use pilots (both opt-in and default).
These efforts will be followed over the next few years by:
• Evaluating opt-in and pilot time-of-use rates in preparation for widespread enrollment.
• Propose a default time-of-use rate structure to begin in 2019, assuming statutory
conditions have been met.
• Phase in a superuser surcharge that will signal to customers when their usage is far in
excess of the typical household and that conservation steps should be taken.
The IOUs may request a fixed monthly charge, but only after the CPUC has evaluated
which, if any, costs are appropriate to collect through a fixed charge and how to do so fairly.
Implementation would not begin until after time-of-use rates have been in place for one
year.
With expanded use of time-of-use rates, it is increasingly important that the definitions of
periods reflect the changes in hourly system costs from increasing penetration of renewable
resources. Ongoing rate design proceedings will refine the process used to define and
update time-of-use periods.
Recommendation 7: Improve Transparency of Renewable Generation Costs
As California’s renewable portfolio continues to grow, it becomes increasingly important to
track publicly available information on costs of recently built renewable projects,
particularly smaller projects. This information helps decision makers understand key cost
trends and drivers in California and supports statewide renewable planning efforts.
Transition to Time-of-Use Rates, Proposed Decision of SLJs McKinney and Halligan, April 21, 2015,
http://docs.cpuc.ca.gov/PublishedDocs/Efile/G000/M151/K305/151305677.PDF.
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The Energy Commission conducted a study on how costs of renewable DG vary based on
location, 481 and the Distributed Energy Resource Pilot Study is examining the value of DG and
other distributed resources in helping to meet state policy goals. However, additional work
is needed on improving the Energy Commission’s data collection process to track publicly
available information on the costs of recently built renewable projects.
Recommendation 8: Strengthen Links Between Transportation and Clean Electrification
Although the Renewable Action Plan was focused on renewable electricity, it also
recognized the importance of electrifying the transportation system to meet California’s
GHG reduction goals. There are also potential benefits from encouraging electric vehicle
charging during times of low load and high wind generation to improve the value of wind
energy, and from using “vehicle-to-grid” services to provide grid support. This
recommendation also emphasized the need for transportation electrification in
disadvantaged communities because they often face disproportionate impacts from burning
fossil fuels.
California has made significant progress on efforts to support electrification of the
transportation system. Since the Renewable Action Plan was adopted, the Energy
Commission’s Alternative and Renewable Fuel and Vehicle Technology Program has
awarded nearly $40 million for plug-in electric vehicle infrastructure, including charging
stations for multiunit dwellings, workplaces, and highways. Examples of projects in
environmentally high-risk communities or areas with environmental justice indicators
include:
• EV Connect – Public charging at five transit parking areas for the Los Angeles County
Metropolitan Transit Authority (Completed 12/31/2013).
• Clipper Creek – Upgrade legacy public chargers throughout California (Completed
6/30/2014).
• Alameda-Contra Costa Transit District – Hydrogen fueling station to support 12
hydrogen fuel cell buses in the transit fleet (Completed 11/30/2014).
• AeroVironment – Charging for Car2Go vehicles at apartment venues (Completed
3/28/2015) and YMCAs (Planned completion 2/28/2016).
• Green Charge Networks, LLC—Installation of 16 DC fast charging stations with batterystorage
and building management systems at sites throughout California (Planned
completion 3/31/2016).
481 California Energy Commission consultant report, Distributed Generation Integration Cost Study,
Navigant Consulting, Inc., September 2014, http://www.energy.ca.gov/2013publications/CEC-200-
2013-007/CEC-200-2013-007-REV.pdf.
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• Southern California Regional Collaborative – Public charging at 315 sites that potentially
could include hospitals and medical centers (Planned completion 6/30/2016).
• Southern California Public Power Authority—Four level 2 electric vehicle chargers and
nine electric vehicle DC fast chargers in various Southern California locations (planned
completion 7/1/2016).
The program has also awarded more than $30 million for electric trucks and buses in
sensitive port areas, including:
• Transpower – Heavy-duty electric truck manufacturing (Completed 9/30/2013).
• Wrightspeed – Range-extended electric drive systems for medium- and heavy-duty
delivery and goods movement vehicles (Completed 10/31/2013).
• Electric Vehicle International – Manufacture and assembly of components for electric
drive medium-duty delivery vehicles (Completed 5/8/2015).
• Kenworth Truck Company – Electric hybrid Class 8 goods movement truck (Completed
5/15/2015).
• Electric Power Research Institute – Plug-in electric hybrid delivery trucks (Planned
completion 3/31/2016).
• Electricore – Plug-in electric delivery trucks (Planned completion 3/31/2016).
• CALSTART – Plug-in electric shuttle buses and drayage trucks, and hybrid electric
drayage trucks (Planned completion 3/31/2018).
• Motiv Power Systems—Demonstration of Class C electric school buses in the school
districts of Los Angeles Unified, Kings Canyon Unified, and Colton Joint Unified
(Planned completion 5/31/2018).
There has also been progress on improving the link between planning for renewable energy,
the distribution system, and zero-emission vehicles. In May 2014, the Energy Commission
published the California Statewide Plug-In Electric Vehicle Infrastructure Assessment with the
assistance of the National Renewable Energy Laboratory. The report provides
recommendations for plug-in vehicle infrastructure planning and provides guidance to local
communities and regions. 482
In addition, the Energy Commission funded 11 Regional Plug-In Electric Vehicle Planning
Grants to develop regional plans for infrastructure, streamlining of permitting and
inspection processes, building code updates, and consumer education and outreach.
482 California Energy Commission, California Statewide Plug-In Electric Vehicle Infrastructure
Assessment, May 2014, http://www.energy.ca.gov/2014publications/CEC-600-2014-003/CEC-600-2014-
003.pdf.
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Regions that received grants included the Bay Area, the Central Coast, the Coachella Valley,
Monterey, North Coast, the Sacramento Valley, San Diego, the San Joaquin Valley, Southern
California, the Tahoe-Truckee region, and Upstate. Energy Commission staff continues to
meet regularly with each planning region to provide coordination and share lessons
learned.
The Energy Commission’s Alternative and Renewable Fuel and Vehicle Technology
Program held solicitations for alternative fuel readiness plans and zero-emission vehicle
readiness in 2013 and 2014, with awards to 24 projects totaling $5.6 million. In 2015, the
Energy Commission also funded $3.3 million for zero-emission vehicle implementation
efforts to assist regions with implementing their plans. The Commission is also supporting
various vehicle-to-grid projects, including cofunding a demonstration project with the
United States Department of Defense that is scheduled for completion in March 2016.
Strategy 3: Reduce Time and Costs of Renewable Interconnection
and Integration
Strategy 3 focused on the need to minimize costs and requirements for renewable
integration, and on improving and reducing the costs of integration tools and technologies
like storage, demand response, and the most effective use of the existing natural gas-fired
power plant fleet.
Recommendation 9: Consider Environmental and Land-Use Factors in Renewable
Scenarios
Recommendation 9 was intended to promote the use of environmental and land-use factors
in renewable scenarios that are used in long-term procurement and transmission planning.
Since the Renewable Action Plan was adopted in 2013, California’s energy agencies have
been working together to identify areas in the state with high renewable potential and
relatively low environmental conflicts, as well as areas with sensitive environmental issues
where permitting costs and challenges are likely to be high. The Energy Commission has
identified environmental issues with new projects and is involved in analyzing the most
appropriate areas for renewable generation and transmission to coordinate and streamline
renewable project permitting.
As part of that effort, the Energy Commission recommended that environmental and landuse
information from the DRECP be incorporated into the renewable scenarios used in the
CPUC’s Long-Term Procurement Plan proceeding and the California ISO’s Transmission
Planning Process.
In the 2014 IEPR Update, the Energy Commission recommended that California should
improve its ability to perform landscape-scale analysis, and is leading an effort with local,
state, and federal partners and other stakeholders to assess the available data and tools,
identify knowledge and other gaps, and develop the ability to perform this type of analysis.
This effort, which is continuing under the 2015 IEPR, is focused outside the DRECP area and
includes the western United States and potential international partners in the western grid.
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Recommendation 10: Monitor Status of California ISO-Approved Transmission
Projects to Ensure Timely Completion
California needs to continue to develop the transmission infrastructure necessary to deliver
remote renewable generation to load centers and meet reliability and economic needs. The
2013 IEPR listed 17 transmission projects approved by the California ISO, the Imperial
Irrigation District, and the Los Angeles Department of Water and Power that will enable
California to meet the 33 percent RPS by 2020. Since publication of that report, the California
ISO approved two more major transmission projects in its 2013-2014 Transmission Plan—the
Delaney-Colorado River and Harry Allen-Eldorado projects. Of the 17 original projects
listed in the 2013 IEPR, four are now operating and one was removed from the list. With the
two new projects approved by the California ISO, the Energy Commission is now tracking
14 transmission projects to support renewable delivery.
In its 2014-2015 Transmission Plan, the California ISO did not identify a need for new
transmission projects to support the RPS, given the transmission projects already approved
or progressing through the permitting process.
Recommendation 11: Streamline Transmission Permitting in California
Recommendation 11 was intended to reduce the amount of time needed to plan, license, and
build major transmission facilities in California to support the state’s renewable electricity
goals. Identifying transmission routes and performing environmental analyses for these
major transmission projects typically does not begin until the California ISO determines the
projects are needed, which can occur about the same time as the renewable generators that
need the transmission are ready to begin construction. This means that transmission projects
can lag behind generation projects by three or more years.
In May 2013, the Energy Commission conducted a workshop to discuss the need for
synchronization between generation and transmission planning and permitting. Workshop
participants concluded that the California ISO’s Generator Interconnection and
Deliverability Allocation Procedures and the annual Transmission Planning Process
represent a large improvement in how new policy-driven transmission projects are
identified. However, the 2013 IEPR noted this does not ensure that transmission will be built
by the time the generation is available. This creates significant risks for generators because
their power purchase agreements often require their generation to be fully deliverable
during peak conditions, and full deliverability may require transmission upgrades. The 2013
IEPR recommended that California’s energy agencies should evaluate the cost-effectiveness,
prudency, and alternatives for requiring full deliverability for future renewable generation
that is procured to meet RPS requirements.
In support of this recommendation, CPUC staff prepared five study scenarios for the
California ISO to begin investigating the impacts of higher RPS targets on transmission
planning. The California ISO selected two “energy-only” scenarios that address a 50 percent
RPS portfolio by 2030 and will assume that additional generation to meet the renewable net
short will not require full deliverability. The 2015 special study provides an opportunity to
A-11

inform future transmission planning cycles without a direct impact on the current
transmission plan.
Successful identification of transmission corridors requires consideration of environmental
information early in transmission planning. Toward that end, the Energy Commission
funded a consultant report that provides a high-level assessment of the environmental
feasibility of several transmission alternatives under consideration by the California ISO to
address reliability and other system challenges arising from the closure of the San Onofre
Nuclear Generating Station. 483 While the alternatives may provide electrical solutions for
addressing challenges, the report examined the likely siting constraints that may have to be
considered during the environmental permitting process for each potential alternative. The
report findings demonstrate that most of the transmission projects will likely encounter
serious challenges for attaining land-use permits, and an early screening of environmental
considerations in the California ISO’s transmission planning process may effectively
identify a short list of the most feasible projects for further consideration in planning
studies.
Another streamlining consideration for the energy regulatory agencies is to encourage
utilities to propose transmission projects that are “right-sized” to meet current and future
needs and to avoid the risk of stranded assets by approving transmission projects are
located near or in existing corridors. This issue of “right-sizing” was first identified in the
2011 IEPR proceeding in which the Energy Commission considered ways to make better use
of the existing grid by allowing projects to be upsized beyond what is needed to provide
unused capacity for future use. Upsizing could maximize the value of land associated with
transmission investments that are already needed, while avoiding costlier upgrades to
accommodate additional development that may be needed in the future.
Recommendation 12: Develop a Dialogue on Distribution Planning and
Opportunities for a More Integrated Distribution Planning Process
California’s transmission planning processes are well-developed and transparent, allowing
all stakeholders to provide input into and understand the planning decisions as they are
made. However, the state lacks a similarly comprehensive planning process for the
distribution system, which can lead to interconnection delays, lost opportunities for
strategic deployment of distributed resources, and increased costs.
There has been some progress on this recommendation. Utilities submitted detailed
distribution resource plans on July 1, 2015, as required by the CPUC’s AB 327 Distribution
Resource Plan rulemaking (R.14-08-013). The plans identify prime locations for distributed
483 California Energy Commission, Transmission Options and Potential Corridor Designations in
Southern California in Response to Closure of San Onofre Nuclear Generation Station (SONGS) –
Environmental Feasibility Analysis, May 2014, and two addenda (September 2014 and January 2015),
http://www.energy.ca.gov/2014publications/CEC-700-2014-002/index.html.
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energy resources, evaluate locational benefits, propose mechanisms to deploy cost-effective
distributed resources, identify utility spending needed to integrate distributed resources
into distribution planning, and identify barriers to deployment. 484
Another effort is the “More Than Smart” working group that is led by California ISO staff
and includes the Energy Commission, the CPUC, utilities, and other stakeholders. The
working group is an offshoot of the “More Than Smart” paper published by the Greentech
Leadership Group which describes a framework to improve the distribution grid. 485 The
working group is focused on developing a transparent distribution plan integrated with all
other state energy planning and is discussing how to integrate the utilities’ new distribution
resource plans into other statewide planning efforts, such as the CPUC’s Long-Term
Procurement Plan proceeding, the California ISO’s Transmission Planning Process, utility
rate cases, and the Integrated Energy Policy Report proceeding. The working group
provides regular updates at CPUC workshops held under the Distribution Resource Plan
proceeding.
Recommendation 13: Disaggregate the Energy Commission’s Demand Forecast
In the Renewable Action Plan, the Energy Commission committed to evaluating ways to
disaggregate, or provide greater detail for, its electricity demand forecast beyond the utility
planning area level to give stakeholders location-specific data on electricity demand. The
first step for this recommendation was providing forecast results by climate zone. In the
2013 IEPR, the Energy Commission’s electricity demand forecast included 16 climate zones
in addition to the usual eight utility planning areas. 486 The 2015 IEPR forecast will include 20
climate zones and also redefine the planning areas to be more consistent with the balancing
authority areas in the state. The Energy Commission will continue to examine further
geographic detail in future forecasts contingent staff resources and data availability.
Recommendation 14: Create a Statewide Data Clearinghouse for Renewable
Energy Generation Planning
Recommendation 14 was to create a statewide renewable data clearinghouse to help
coordinate land-use planning with utility system planning at both the distribution and
transmission levels. The success of this recommendation depended on the public availability
of data, which continues to be a challenge. Data collection for the energy sector and
484 California Public Utilities Commission, Distribution Resources Plan Applications (filed July 1,
2015), http://www.cpuc.ca.gov/PUC/energy/drp/.
485 Greentech Leadership Group and Resnick Sustainability Institute, More Than Smart – A Framework
to Make the Distribution Grid More Open, Efficient, and Resilient, http://greentechleadership.org/wpcontent/uploads/2014/08/More-Than-Smart-Report-by-GTLG-and-Caltech.pdf.
486 California Energy Commission, California Energy Demand 2014-2024 Final Forecast, January 2014,
http://www.energy.ca.gov/2013_energypolicy/documents/#adoptedforecast.
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accessibility to data can be complex and contentious, and until enough useful data are
publicly available, the ability to establish a statewide data clearinghouse is limited.
There are, however, some current data sources that are useful for planning:
• In May 2014, the CPUC published a decision under rulemaking 08-12-009, which
adopted rules that provide access to energy usage data to local governments,
researchers, and state and federal agencies when that access is consistent with state law
and procedures protecting the privacy of consumer data. 487
• As part of the CPUC’s Rule 21 proceeding, California’s investor-owned utilities must file
quarterly Net Energy Metering interconnection reports. 488
• The Energy Commission continues to collect and post renewable energy statistics for
California on its website. 489
• Several California counties have begun posting useful information on where renewable
projects are filing for permits.
Recommendation 15: Enable Deployment of Advanced Inverter Functions for Volt-
Var and Frequency Management
Successful integration and management of increasing amounts of distributed solar
photovoltaic resources will require inverters that can provide fast and flexible control of
output current.
In January 2013, the Energy Commission and the CPUC formed the Smart Inverter Working
Group to develop technical recommendations for inverter-based distributed resources to
support operation of the distribution system. The working group includes utilities, inverter
manufacturers, renewable developers, government, and other organizations and has held
weekly conference calls since it began in 2013.
The group is developing technical recommendations in three phases. Phase 1
recommendations included seven critical autonomous functions, which were adopted by
the CPUC in December 2014 and will be implemented by mid-2016.
In Phase 2, the working group focused on inverter communication capabilities for
monitoring, updating settings, and control. The group submitted the Phase 2 document to
487 California Public Utilities Commission, Decision 14-05-016, Decision Adopting Rules to Provide
Access to Energy Usage and Usage-Related Data While Protecting Privacy of Personal Data, May 1, 2014,
http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M090/K845/90845985.PDF.
488 California Public Utilities Commission, http://www.cpuc.ca.gov/PUC/energy/rule21.htm.
489 California Energy Commission, http://energyalmanac.ca.gov/electricity/ and
http://www.energy.ca.gov/renewables/tracking_progress/index.html.
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CPUC staff in February 2015, and the CPUC is coordinating with the IOUs on
implementation.
In March 2015, the group began working on Phase 3 recommendations, which will include
advanced inverter functionality, and is discussing priorities for which functions to
consider. 490
Recommendation 16: Develop a Forward Procurement Mechanism
The Energy Commission recommended a forward procurement mechanism for 3-5 years
ahead to provide revenue streams for the flexible capacity resources needed to integrate
renewable resources and allowing all integration resources—such as demand response,
energy storage, and flexible natural gas-fired power plants—to compete on a level playing
field.
There has been little progress on this recommendation. The CPUC established the 2014
Long-Term Procurement Plan proceeding in late 2013, which was focused principally on
flexibility issues at the 10-year forward horizon. 491 Efforts of parties to develop satisfactory
forward projections of flexibility requirements were unsuccessful, and the CPUC terminated
this portion of the proceeding in March 2015. Instead, the CPUC has initiated a model
development effort for the balance of 2015 to improve the models for use in the upcoming
2016 Long-Term Procurement Plan proceeding.
In early 2014, the CPUC established the Joint Reliability Plan rulemaking which investigated
whether to extend resource adequacy requirements from the one-year forward horizon to a
three-year forward horizon. 492 In October 2014, CPUC staff issued a report summarizing
several workshops, but parties were opposed to mandating the current interim method of
setting forward flexibility requirements and the CPUC suspended this portion of the Joint
Reliability Plan rulemaking in January 2015. As of July 2015, the portion of the proceeding
addressing forward planning requirements (system, local and flexible) is awaiting CPUC
Energy Division staff analyses intended to shed light on the risk of retirement for existing
generators.
490 For more information about the Smart Inverter Working Group, see
http://www.cpuc.ca.gov/PUC/energy/rule21.htm.
491 California Public Utilities Commission, R.13-12-010, Order Instituting Rulemaking to Integrate and
Refine Procurement Policies and Consider Long-Term Procurement Plans, December 19, 2013,
http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M084/K241/84241040.PDF.
492 California Public Utilities Commission, R.14-02-001, Order Instituting Rulemaking to Consider
Electric Procurement Policy Refinements pursuant to the Joint Reliability Plan, February 5, 2014,
http://docs.cpuc.ca.gov/PublishedDocs/Published/G000/M087/K779/87779434.PDF.
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Recommendation 17: Define Clear Tariffs, Rules, and Performance Requirements
for Integration Services
Recommendation 17 focused on the need to develop a comprehensive package of clear
tariffs, rules, and performance requirements for renewable integration services. The
California ISO has led several efforts contributing to this effort. These include working
closely with stakeholders to develop wholesale demand response products that can
participate directly in the market, as well as educational forums to clarify existing
requirements, rules, and market products for energy storage and aggregated distributed
resources to participate in California ISO markets.
The California ISO, in coordination with energy agencies and stakeholders, has also
developed detailed roadmaps for energy storage, demand response, and energy efficiency
that include pathways for bringing more of these resources into the system over the next
several years and identify activities and milestones needed to make that happen.
Most importantly, in July 2015, the California ISO Board of Governors approved rules and
processes to allow aggregated distributed resources to participate in the wholesale energy
market. This effort is meant to open a pathway for smaller distributed resources such as
rooftop solar, energy storage, and plug-in electric vehicles to participate effectively in the
California ISO market. 493
Recommendation 18: Provide Regional Solutions to Renewable Integration
The Renewable Action Plan recognized the value of near-term, low-cost integration
solutions available in the Western Interconnection, such as expanding subhourly dispatch
and intrahour scheduling, promoting dynamic transfers between balancing authorities, and
accessing greater flexibility in the dispatch of existing generating plants.
There has been major progress on this recommendation. The California ISO and PacifiCorp
announced a partnership in February 2013 to develop an Energy Imbalance Market (EIM)
that would operate across participating balancing areas. The EIM began operating in
November 2014 and will be joined by NV Energy in the fall of 2015 and by Puget Sound
Energy and Arizona Public Service in October 2016. 494
The EIM is an important renewable integration tool because it allows participants to
leverage resources across the entire region, as well as providing the added benefit of more
frequent dispatching in real time to make the best use of available energy supplies. The
493 California Independent System Operator,
http://www.caiso.com/Documents/Decision_ExpandingMetering_TelemetryOptions-Memo-
Jul2015.pdf.
494 California Independent System Operator,
http://www.caiso.com/informed/Pages/EIMOverview/Default.aspx.
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California ISO announced in April 2015 that the total gross benefits of the EIM since it began
totaled more than $11 million.
The California ISO and PacifiCorp have also entered into a memorandum of understanding
to explore PacifiCorp’s becoming a participating transmission owner in the California
ISO. 495 A comprehensive benefits study is underway and is expected to be completed in fall
of 2015. The California ISO expects this regional partnership to provide important benefits
such as reduced costs for customers and market participants, reduced carbon emissions and
more efficient use and integration of renewable energy, and enhanced reliability by
increasing visibility across grids. 496
Recommendation 19: Ensure Adequate Natural Gas Pipeline Infrastructure
Natural gas-fired power plants remain an important tool to integrate increasing amounts of
variable renewable resources while maintaining grid reliability. Making the best use of the
state’s natural gas fleet and ensuring that these plants can be called on when needed
requires adequate natural gas pipeline infrastructure and better alignment of electricity and
natural gas markets. Efforts in support of this recommendation include the following:
• In April 2013, ColumbiaGrid released a study on electric transmission system reliability
issues with a hypothetical limitation of gas supply to electric generators along the
Interstate 5 (I-5) corridor, which found that the electric transmission system performed
acceptably under the stressed conditions. Further, in a 2013 IEPR workshop on natural
gas issues, the California ISO stated that short-term operational coordination between
natural gas supply and electricity production in California has been occurring with few
incidents. The 2013 IEPR also included a report on natural gas infrastructure, natural gas
and electric system interactions, and impacts to the natural gas market as a result of
renewable integration.
• The Federal Energy Regulatory Commission (FERC) issued an order in March 2014
requiring all interstate pipelines to set up a system to post offers to buy excess capacity,
which was intended to help improve the flow of natural gas to facilities such as gas-fired
electric generators. 497
• In July 2014, Energy+Environmental Economics (E3) released a report on natural gas
infrastructure adequacy in the western interconnection which concluded that it is
495 “PacifiCorp to Study Joining the California ISO,” April 14, 2015,
http://www.pacificorp.com/about/newsroom/2015nrl/study-joining-california-iso.html.
496 California Independent System Operator, http://www.caiso.com/Documents/FAQ-
ExpandingRegionalEnergyPartnerships.pdf.
497 Federal Energy Regulatory Commission, “FERC Announces Reforms to Improve Gas-Electric
Coordination,” news release, March 20, 2014, http://www.ferc.gov/media/news-releases/2014/2014-
1/03-20-14-M-1.asp#.VYMFg6Hn_cs.
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technically feasible to meet the variable gas demands needed to integrate high
penetrations of renewables in the west. 498 The report noted, however, that as
penetrations of variable renewable resources increase, forecasting the amount of gas
needed to serve gas generators will become increasingly challenging.
• Also in 2014, Pacific Gas and Electric Company and Southern California Gas Company
submitted biennial advice filing letters to the CPUC demonstrating they have adequate
backbone natural gas transmission capacity to meet both current and forecasted
demand.
• Energy Commission staff continue to monitor FERC proceedings on natural gaselectricity
harmonization issues. FERC recently issued an order under Docket No.
RM14-2-000, which revises FERC regulations to better coordinate the scheduling of
wholesale natural gas and electricity markets to reflect increasing reliance on natural gas
for electricity generation and to provide additional scheduling flexibility to shippers on
interstate gas pipelines. 499
Strategy 4: Promote Incentives for Renewables that Create In-State
Jobs and Benefits
Strategy 4 focused on economic development opportunities from supporting renewable
projects and technologies by creating in-state jobs and supporting in-state industries,
including manufacturing and construction.
Recommendations 20-22: Better Align Workforce Training to Needs; Enhance
Linkage Between Clean Energy Policies, Workforce, and Employers; and Support
the Innovation Hub Initiative at the Governor’s Office of Business and Economic
Development
From 2009 to 2012, the Energy Commission had a strong role in workforce development and
education in California through its distribution of American Recovery and Reinvestment
Act funding. That commitment to workforce development is continuing through the efforts
of the agency’s Energy Research and Development Division. In February 2013, the
California Smart Grid Center at California State University, Sacramento, completed a
strategic plan for Smart Grid workforce development using funding from the Energy
Commission. In addition, the market facilitation element of the Electric Program Investment
498 Energy+Environmental Economics, Natural Gas Infrastructure Adequacy in the Western
Interconnection: An Electric System Perspective, Phase 2 Report, July 2014,
https://www.ethree.com/documents/E3_WIEB_Ph2_Report_full_7-28-2014.pdf.
499 Federal Energy Regulatory Commission, Docket No. RM14-2-000, Order No. 809, Coordination of
the Scheduling Processes of Interstate Natural Gas Pipelines and Public Utilities, April 16, 2015,
http://ferc.gov/whats-new/comm-meet/2015/041615/M-1.pdf.
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Charge Program funds the strengthening of the clean energy workforce by creating tools
and resources that connect the clean energy industry to the labor market.
The California Workforce Investment Board continues to be active in workforce training and
has a five-year strategic plan that recognizes the importance of clean energy jobs in
California. The plan identifies a wide variety of green trades ranging from carpenters and
electricians to solar installers. The Board has also received $3 million in Proposition 39 funds
to develop and implement a competitive grant program for eligible workforce training
organizations to prepare disadvantaged youth, veterans, and others for employment in
clean energy fields.
California also has Clean Technology and Renewable Energy Partnership Academies that
were established by legislation in 2011, with annual funding established in 2013 of $8
million per year through 2017, for about 100 academies focused on green energy and
technologies. The academies are available to students in grades 9-12 and provide career
technical education in the fields of energy or water conservation and renewable energy.
Strategy 5: Coordinate Financing and Incentives for Critical Stages
of Development
Strategy 5 centered on the importance of providing funding during key stages of the
renewable research and development continuum, and of coordinating financing and
incentive programs to provide the most value.
Recommendations 23-26: Advance R&D for Existing and Colocated Renewable
Technologies, Innovative Renewable Technologies, Renewable Integration, and
Proactive Siting of Renewable Projects
The primary action items for Recommendations 23-26 were to ensure that all research
proposals are evaluated through a publicly vetted process, leverage cofunding
opportunities, avoid duplication, and publish all research results on the Energy
Commission’s website and make the information available to renewable developers and
generators, to integration service providers, grid system operators, regulatory agencies,
policy makers, and research groups, as appropriate.
Since 2010, the Energy Commission’s Energy Research and Development Division has
awarded more than $200 million to projects that support the recommendations in the
Renewable Energy Action Plan. Consistent with the recommendations of the action plan,
each award was evaluated through a public process with results published on the Energy
Commission’s website and provided to all interested stakeholders, and every effort is made
to leverage other funding opportunities when available and avoid duplicative research.
More information about projects funded that support each recommendation is provided
below.
The Energy Commission has funded 41 projects totaling more than $70 million to support
existing and co-located renewable technologies, including planning projects to reduce
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installation and maintenance costs, improving reliability and performance; developing
community-scale bioenergy, conducting environmental impact assessment and mitigation,
examining opportunities for synergies from combining renewable technologies, reducing
the cost of distributed PV; integrating advanced inverter technologies and smart grid
components; and identifying strategies to make bioenergy projects more economical.
Table 16: Projects Funded Since 2010 to Advance Research and Development for Existing and
Colocated Renewable Technologies ($70,257,605)
Project Title Researcher Amount Status
Air Quality Implications of
Electrification and Renewable Energy
Options
Advanced Power and Energy
Program – UC Irvine $835,711 Active
Considering Climate Change in
Hydropower Relicensing
Hyperlight Low-Cost Solar Thermal
Technology
Economically and Environmentally
Viable Strategies for Conversion of
Bioresources to Power
Air Quality Issues Related to Using
Biogas from Anaerobic Digestion of
Food Waste
Air Quality Implications of using Biogas
(AQIB) to Replace Natural Gas in
California
Regents of the University of
California (University of
California, Davis)
Combined Power Cooperative
(formerly Advanced Lab Group
Cooperative)
Advanced Power and Energy
Program – UC Irvine
$299,970 Active
$1,000,000 Active
$397,236 Active
CSU Fullerton $164,201 Active
Regents of the University of
California (University of
California, Davis)
$775,064 Active
Bay Area Biosolids to Energy Delta Diablo Sanitation District $999,924 Active
Gasification of Almond Shell Biomass The Regents of the University
for Natural Gas Replacement
of California (CIEE)
$463,852 Active
Breakthrough Power Density for
Rooftop PV Applications
Sun Synchrony $475,095 Active
Pollution Control and Power
Generation for Low Quality Renewable
The Regents of the University
of California; University of $1,499,386 Active
Fuel Streams
California, Irvine
The Lakeview Farms Dairy
ABEC #3 LLC, dba Lakeview
Farms Dairy Biogas
$4,000,000 Active
The West Star North Dairy
ABEC #2 LLC, dba West Star
North Dairy Biogas
$4,000,000 Active
Organic Energy Solutions Community
Scale Digester with Advanced
Organic Energy Solutions $5,000,000 Active
Interconnection to the Electric Grid
Lowering Food-Waste Co-digestion
Costs through an Innovative
Combination of a Pre-sorting
Technique and a Strategy for Cake
Solids Reduction
Kennedy/Jenks Consultants $1,496,902 Active
A-20

Project Title Researcher Amount Status
Installation of a Lean-Burn Biogas
Engine with Emissions Control to
Comply with Rule 1110.2 at a
Wastewater Treatment Plant in South
Biogas & Electric, LLC $2,249,322 Active
Coast air Quality
Enabling Anaerobic Digestion
Deployment for Municipal Solid Wasteto-Energy
North Fork Community Power Forest
Bioenergy Facility
Modular Biomass Power Systems to
Facilitate Forest Fuel Reduction
Treatments
Lawrence Berkeley National
Laboratory
The Watershed Research and
Training Center
$4,300,000 Active
$4,965,420 Active
West Biofuels, LLC $2,000,000 Active
Interra Reciprocating Reactor for Low-
Cost & Carbon-Negative Bioenergy
Interra Energy $2,000,000 Active
Cleaner Air, Cleaner Energy:
Converting Forest Fire Management
Waste to On-Demand Renewable
All Power Labs Inc. $1,990,071 Active
Energy
Advanced Recycling of MSW Taylor Energy $1,499,481 Active
The SoCalGas Waste-to-Bioenergy The Southern California Gas
Applied R&D Project
Company
$1,494,736 Active
Paths to Sustainable Distributed
Generation through 2050: Matching
Local Waste Biomass Resources with
Grid, Industrial, and Community Needs
Lawrence Berkeley National
Laboratory
$1,500,000 Active
Low-Cost Biogas Power Generation
with Increased
Efficiency and Lower Emissions
Meteorological Observations of
Precipitation Processes to Improve
Hydropower Forecasting
California Landfill-Based Solar Projects
Waste Vegetable Oil Driven CHP for
Fast Food Restaurants
Production of Substituted Natural Gas
from the Wet Organic Waste by
Utilizing PDU-Scale Steam
Hydrogasification Process
Demonstration of Community-Scale,
Low-Cost, Highly efficient PV and
Energy management system at
the Chemehuevi Community Center
Low-Emission Renewable Power
Generation System
Community-Scale Renewable
Combined Heat and Power Project
Dairy Renewable Combined Heat and
Power
InnoSepra, LLC $1,318,940 Active
National Oceanic and
Atmospheric Administration $1,105,000 Completed
Project Navigator, LTD
Altex Technologies
Corporation
University of California,
Riverside
The Regents of the University
of
California
$120,000 Completed
$1,435,575 Completed
$649,214 Completed
$2,588,906 Pending
Recology Bioenergy $1,500,000 Pending
Recology Bioenergy $1,915,500 Pending
ABEC #4 $3,000,000 Pending
A-21

Project Title Researcher Amount Status
Advancing Biomass Combined Heat
and Power Technology to
Support Rural California, the
Environment, and the Electrical Grid
Sierra Institute for Community
and Environment
$2,603,228 Pending
College of San Mateo Internet of
Energy
Demonstration of Community-Scale,
Low-Cost, Highly Efficient PV and
Energy Management System
Advancing Novel Biogas Cleanup
Systems for the Production of
Renewable Natural Gas
Renewable Natural Gas Production
from Woody Biomass via Gasification
and Fluidized-Bed
Cost Reduction for Biogas Upgrading
via a Low-Pressure, Solid-State Amine
Scrubber
Las Gallinas Valley Biogas Energy
Recovery System (BERS) Project
Investigation and Implementation of
Improvements to Biogas Production
Using Micronutrients, Operational
Methodologies, and Biogas Processing
Equipment to Enable Pipeline Injection
of Biomethane
Source: Energy Commission staff
Prospect Silicon Valley dba
Bay
Area Climate Collaborative
(BACC)
$2,999,601 Pending
UC Davis $1,238,491 Pending
Institute of Gas Technology
dba Gas Technology Institute
(GTI)
The Regents of the University
of California, San Diego
$1,000,000 Pending
$1,000,000 Pending
Mosaic Materials, Inc. $1,000,000 Pending
Las Gallinas Valley Sanitary
District
$999,070 Pending
Biogas Energy Inc. $415,000 Pending
To advance research and development for innovative renewable technologies, the Energy
Commission has funded projects totaling more than $20 million to bring technologies closer
to commercialization, examine the potential of technologies on the horizon, develop data
and tools to support market facilitation, verify the performance of innovative technologies,
and develop technologies in the areas of biomass conversion, offshore wind, concentrating
solar power, small hydro, and geothermal. Other projects have evaluated strategies to
reduce peak demand; minimize the environmental impacts of energy generation, and bring
technologies to market that provide increased environmental benefits, greater system
reliability, and reduced system costs.
Table 17: Projects Funded Since 2010 to Advance Research and Development for Innovative
Renewable Technologies ($20,230,777)
Project Title Researcher Amount Status
Smart Inverter Interoperability
Standards
SunSpec Alliance $2,000,000 Active
Mass-Manufactured, Air Driven
Trackers for Low-Cost, High-
Performance Photovoltaic Systems
Sunfolding, Inc. $1,000,000 Active
A-22

Project Title Researcher Amount Status
Demonstration of integrated
photovoltaic systems and smart Lawrence Berkeley National
inverter functionality utilizing advanced Laboratory
$1,000,000 Active
distribution systems
Exploration Drilling and Assessment of Renovitas, LLC
Wilbur Hot Springs, Colusa County,
$264,229 Completed
California
High Solar PV Penetration Modeling UC San Diego $500,000 Completed
SMUD's Smart Grid Pilot at Anatolia Sacramento Municipal Utility
$500,000 Completed
Technologies for extracting valuable
metals and compounds from
geothermal fluids
Caldwell Ranch Exploration and
Confirmation Project
UC Davis West Village Energy
Initiative: American Recovery and
Reinvestment Act Cost-Share Funding
SMUD Community Renewable Energy
Deployment
Plumas Energy Efficiency and
Renewable Management Action Plan
Energizing Our Future: Community
Integrated Renewable Energy
Assessment
Davis Future Renewable Energy and
Efficiency
MaxSun- A Novel Community-Scale
Renewable Solar Power System for
California
Predictable Solar Power and Smart
Building Management for California
Communities
Renewable Energy Regional
Exploration Project
Repowering Humboldt with
Community-Scale Renewable Energy
Camp Pendelton Area 52 FractalGrid
Demonstration Project
Assessing Smart Inverters and
Consumer Devices to Enable more
Residential Solar Energy
Self-Tracking Concentrator
Photovoltaics for Distributed
Generation
Source: Energy Commission staff
District
Simbol, Inc.
Calpine Corporation
Regents of the University of
California (University of
California, Davis)
Sacramento Municipal Utility
District
Sierra Institute for Community
and Environment
Department of the
Environment- City and County
of San Francisco
City of Davis
Cogenra Solar, Inc.
Cool Earth Solar, Inc.
South Tahoe Public Utility
District
Redwood Coast Energy
Authority
Harper Construction Company,
Inc.
$380,000 Completed
$410,000 Completed
$500,000 Completed
$500,000 Completed
$300,000 Completed
$300,000 Completed
$300,000 Completed
$525,000 Completed
$1,726,438 Completed
$139,830 Completed
$1,750,000 Completed
$1,722,890 Completed
EPRI $1,705,487 Pending
Glint Photonics, Inc. $999,994 Pending
The Energy Commission has funded 75 projects to support renewable integration for a total
of $109 million. These include projects to integrate intermittent generation, improve solar
and wind forecasting, develop smart grid technologies and microgrids, and improve energy
storage technologies. Applied research projects that were funded include energy storage,
A-23

grid planning tools, distribution system upgrades, and technology demonstration and
deployment projects for renewable-based microgrids to demonstrate the benefits of local
renewable generation enhanced with load management.
Table 18: Projects Funded Since 2010 to Promote Research and Development for Renewable
Integration ($109,245,960)
Project Title Researcher Amount Status
Renewable Energy Resource,
Technology, and Economic
Regents of the University of
California (University of $2,000,000 Active
Assessments
California, Davis)
Improving Solar & Load Forecasts:
Reducing the Operational Uncertainty
Itron, Inc., dba IBS
$998,926 Active
Behind the Duck Chart
Investigating Flexible Generation Geysers Power Company,
Capabilities at the Geysers
LLC
$3,000,000 Active
Low-Cost Thermal Energy Storage for University of California, Los
Dispatchable CSP
Angeles
$1,497,024 Active
Systems Integration of Containerized Halotechnics
Molten Salt Thermal Energy Storage in
Novel Cascade Layout
$1,500,000 Active
Solar Forecast Based Optimization of
Distributed Energy Resources in the
L.A. Basin and UC San Diego
Microgrid
Improving Short-Term Wind Power
Forecasting Through Measurements
and Modeling of the Tehachapi Wind
Resource Area
Flow Battery Solution to Smart Grid
Renewable Energy Applications
Smart Grid Demonstration Project
Grid-Saver Fast Energy Storage
Demonstration
Demonstration and Validation of PV
Output Variability Modeling
Utility-Scale Solar Forecasting,
Analysis and Modeling
Evaluation and Optimization of
Concentrated Solar Power Coupled
With Thermal Energy Storage
Application of a Solar Forecasting
System to Utility-Sized PV Plants on a
Spectrum of Timescales
Energy Resource Forecasting and
Integration Analysis
Surface Deformation Baseline in
Imperial Valley From Satellite Radar
Interferometry (InSAR)
Borrego Springs Microgrid
Demonstration Project
The Regents of the University
of California, San Diego
University of California - Davis
EnerVault Corporation
Los Angeles Department of
Water & Power
Transportation Power, Inc.
Clean Power Research
EnerNex, LLC
KEMA, Inc.
AWS Truepower, LLC
The Regents of the University
of California (CIEE)
Imageair, Inc.
San Diego Gas & Electric
Company
A-24
$999,984 Active
$1,000,000 Active
$476,428 Active
$1,000,000 Active
$2,000,000 Completed
$450,000 Completed
$450,000 Completed
$447,642 Completed
$442,136 Completed
$322,508 Completed
$672,234 Completed
$2,808,488 Completed

Project Title Researcher Amount Status
Pacific Gas and Electric Energy Pacific Gas and Electric
Storage Demonstration
Company
$3,300,000 Completed
Renewable Resource Management at The Regents of the University
UCSD
of California, San Diego
$2,994,298 Completed
Using High Speed Computing to
Estimate the Amount of Energy
Lawrence Livermore National
Laboratory
Storage and Automated Demand
Response Needed to Support
California’s RPS.
$1,750,000 Completed
Determining Best Location for Energy
Storage to Maximize Effectiveness
With Residential Renewable Generator
Clusters
Electric Vehicle Charging Simulator for
Distribution Grid Feeder Modeling
Wind Ramp − Short-Term Event
Prediction Tool − Development and
Implementation of an Analytical Wind
Ramp Prediction Tool for the CAISO
WindSENSE − Determining the Most
Effective Equipment for the CAISO to
Gather Wind Data for Forecasting
Advanced Control Technologies for
Distribution Grid Voltage and Stability
With Electric Vehicles and Distributed
Renewable Generation
Distribution System Field Study With
California Utilities to Assess Capacity
for Renewables and Electric Vehicles
A Low-Cost Inverter With Battery
Interface for Photovoltaic-Utility
System
Adaptive Power Flow Controls for
Distribution Circuits With Renewables
San Diego Gas & Electric
Company
San Diego Gas & Electric
Company
Regents of the University of
California (University of
California, Davis)
Regents of the University of
California (University of
California, Davis)
Pacific Gas and Electric
Company
$539,350 Completed
$680,000 Completed
$398,662 Completed
$646,661 Completed
$1,535,725 Completed
The Regents of the University
of California (CIEE) $1,167,380 Completed
Texas A&M University
California State University,
Long Beach Research
Foundation
Ballast Energy, Inc
$95,000 Completed
$49,999 Completed
Low-Cost Ultra-Thick Electrode
Batteries for Grid-Level Storage
$95,000 Completed
New Portable Electricity Storage Units University of California, Davis
Using Nanstructured Supercapacitors
$86,420 Completed
Intelligent Energy Management for University of California, Davis
Solar-Powered EV Charging Stations
$94,917 Completed
Cloud Speed Sensor UC San Diego $95,000 Completed
Dampening System Oscillations UC San Diego
Utilizing Phasor Measurement Units
$95,000 Completed
and Photovoltaic Inverters
PEV-Based Active and Reactive Power University of California,
Compensation in Distribution Networks Riverside
$95,000 Completed
Liquid Metal Thermal Energy Storage thermaphase Energy, Inc $95,000 Completed
Vehicle-Grid Integration Roadmap KEMA, Inc. $109,965 Completed
AB 2514 Energy Storage KEMA, Inc. $350,000 Completed
Energy Storage Roadmap KEMA, Inc. $50,000 Completed
A-25

Project Title Researcher Amount Status
Microgrid Assessment and
Recommendation(s) to Guide Future
KEMA, Inc.
$100,000 Completed
Investments.
Strategic Analysis of Energy Storage The Regents of the University
Technology
of California (CIEE)
$324,998 Completed
Enabling Renewable Energy, Energy
Storage, Demand Response and
Energy Efficiency with a Community
Based Master Controller-Optimizer
The Regents of the University
of California, San Diego
$999,949 Completed
Wind Firming Energy Farm Primus Power Corporation $1,000,000 Completed
Sacramento Municipal Utility District
Supervisory Control and Data
Sacramento Municipal Utility
District $1,000,000 Completed
Acquistion Retrofit
California ISO SynchroPhasor
Technology Investment &
Electric Power Group
$999,743 Completed
Implementation
Glendale Water & Power − Marketing. City of Glendale
Public Benefits
$1,000,000 Completed
Solid State Batteries for Grid-Scale Seeo Inc.
Energy Storage
$600,000 Completed
SGIG Distribution Infrastructure Modesto Irrigation District
Substation Upgrades
$149,315 Completed
Burbank Water and Power American Burbank Water and Power
Recovery and Reinvestment Act Smart
Grid Program
$1,000,000 Completed
Advanced Underground CAES
Demonstration Project Using a Saline
Porous Rock Formation as the Storage
Reservoir
Validated and Transparent Energy
Storage Valuation and Optimization
Tool
Pilot Testing and Demonstration of a
Solar Hybrid System With Advanced
Storage and LowTemperature Turbine
to Produce On-Demand Solar
Electricity
Utility Demonstration of Zynth Battery
Technology at $100/kWh or Less to
Characterize Performance and Model
Grid Benefits
High-Temperature Hybrid Compressed
Air Energy Storage
City of Fremont Fire Stations Microgrid
Project
Bosch Direct Current Building-Scale
Microgrid
Demonstrating a Secure, Reliable,
Low-Carbon Community Microgrid at
Blue Lake Rancheria
Pacific Gas and Electric
Company
$1,000,000 Completed
Electric Power Research
Institute $1,000,000 Completed
Cogenra Solar, Inc.
Eos Energy Storage, LLC
Regents of the University of
California, Los Angeles
Gridscape Solutions
Robert Bosch LLC
Humboldt State University
Sponsored Programs
Foundation
$2,530,952 Completed
$2,156,704 Completed
$1,621,628 Completed
$1,817,925 Completed
$2,817,566 Completed
$5,000,000 Completed
A-26

Project Title Researcher Amount Status
Las Positas Community College Chabot-Las Positas
Microgrid
Community College District
$1,522,591 Completed
Demonstration of PEV Smart Charging
and Storage Supporting Grid
Operational Needs
Regents of the University of
California, Los Angeles $1,989,432 Completed
Smart Charging of Plug-In Vehicles
and Driver Engagement for Demand
Management and Participation in
Electricity Markets
Laguna Subregional Wastewater
Treatment Plant Advanced Microgrid
Borrego Springs − A Future
Photovoltaic Based Microgrid
High-Fidelity Solar Power Forecasting
Systems for the 392 MW Ivanpah Solar
Plant (CSP) and the 250 MW California
Valley Solar Ranch (PV)
Addressing Renewable Integration
Issues Impacting DOD Bases in CA
Lawrence Berkeley National
Laboratory
Trane U.S., Inc.
San Diego Gas & Electric
Company
The Regents of the University
of California, San Diego
KEMA, Inc.
$1,993,355 Completed
$4,999,804 Completed
$4,724,802 Completed
$999,898 Pending
$120,288 Pending
High Solar PV Penetration Modeling UC San Diego $500,000 Pending
College of San Mateo Internet of
Prospect Silicon Valley dba
Bay Area Climate
$2,999,601 Pending
Energy
Collaborative
Demonstration of Community–Scale,
Low–Cost, Highly Efficient PV and
Energy Management System
The Regents of the University
of California, Davis $1,238,488 Pending
Demonstration of Community–Scale,
Low–Cost, Highly Efficient PV and
Energy Management System at the
Chemehuevi Community Center
Bosch Direct Current, Building-Scale
Microgrid
Demonstrating a Secure, Reliable,
Low-Carbon Community Microgrid at
the Blue Lake Rancheria
Borrego Springs − A Future
Photovoltaic-Based Microgrid
Renewable Microgrid for the John Muir
Medical Center
City of Fremont Fire Stations Microgrid
Project
Las Positas Community College
Microgrid
Laguna Subregional Wastewater
Treatment Plant Advanced Microgrid
Control of Networked Electric Vehicles
to Enable a Smart Grid With
Renewable Resources
Source: Energy Commission staff
The Regents of the University
of California, Riverside
Robert Bosch LLC
Humboldt State Unversity
Sponsored Programs
Foundation
San Diego Gas & Electric
Company
Charge Bliss, Inc.
Gridscape Solutions
Chabot-Las Positas
Community College District
Trane U.S., Inc.
$2,588,906 Pending
$2,817,566 Pending
$5,000,000 Pending
$4,724,802 Pending
$4,776,171 Pending
$1,817,925 Pending
$1,525,000 Pending
$4,999,804 Pending
The Regents of the University
of California (CIEE) $400,000 Pending
A-27

To support siting and permitting of renewable projects, the Energy Commission has funded
21 projects totaling around $9 million to reduce and resolve environmental barriers to
renewable deployment; develop new technology designs, scientific studies, and decisionsupport
tools to avoid impacts to environmentally sensitive areas and permitting delays;
and provide environmental analysis to support identifying preferred areas for renewable
development such as the San Joaquin Valley.
Table 19: Projects Funded Since 2010 for Proactive Siting of Renewable Projects ($9,196,414)
Project Title Researcher Amount Status
Analysis of Forest Biomass Removal USDA Forest Service, Sierra
on Biodiversity
Nevada Research Center, $1,149,361 Active
Assessing the Long-term Survival and
Reproductive Output of Desert
Tortoises at a Wind Energy Facility
Near Palm Springs, California.
Mapping Habitat Distributions of Desert
Rare Plants from Optimized Data
Use of Habitat Suitability Models and
Head-Start Techniques to Minimize
Conflicts between Desert Tortoises
and Energy Development Projects in
the Mojave Desert
Cumulative Biological Impacts
Framework for Solar Energy Projects
in the California Desert
Potential Habitat Modeling, Landscape
Genetics, and Habitat Connectivity for
the Mohave Ground Squirrel
Methodology for Characterizing Desert
Streams to Facilitate Permitting Solar
Energy Projects
Measure of Carbon Balance in
California Deserts: Impacts of
Widespread Solar Power Generation
Assessment of Offshore Wind
Development Impacts on Marine
Ecosystems
Evaluation of a Passive Acoustic
Monitoring Network for Harbor
Porpoises in California
Development of an Environmental
Impact Assessment Tool for Wave
Energy
Development of a Modeling Tool to
Assess and Mitigate the Effects of
Small Hydropower on Stream Fishes in
a Changing California Climate
Assessment of the Potential
Environmental Impacts of Alternative
Pacific Southwest
U.S. Geological Survey,
Southwest Biological Science
Center
$319,936 Completed
Regents of the University of
California (University of
California, Davis)
$580,907 Completed
Regents of the University of
California (University of
California, Davis) $238,310 Completed
The Regents of the University
of California, Santa Barbara $383,787 Completed
U.S. Geological Survey
$223,755 Completed
California State University,
Fresno Foundation $297,948 Completed
University of California
Riverside $164,879 Completed
University of California Los
Angeles $153,017 Completed
San Jose State University
San Diego State University
University of California Davis
University of California
Berkeley
A-28
$149,815 Completed
$165,000 Completed
$133,000 Completed
$133,000 Completed

Project Title Researcher Amount Status
Energy Scenarios for California
Aerial Line Transect Surveys for
Golden Eagles within the Desert
Renewable Energy Conservation Plan
Area
Research to Improve Golden Eagle
Management in the Desert Renewable
Energy Conservation Planning Area
Population Viability and Restoration
Potential for Rare Plants Near Solar
Installations
Desert Tortoise Spatial Decision
Support System
Effect of Utility-Scale Solar
Development and Operation on Desert
Kit Foxes
Improving Environmental Decision
Support for Proposed Solar Energy
Projects Relative to Mojave Desert
Tortoise
Test of Avian Collision Risk of a
Closed Bladed Wind Turbine
Considering Climate Change in
Hydropower Relicensing
Source: Energy Commission staff
Humboldt State University
Sponsored Programs
Foundation
US Geological Survey
BMP Ecosciences
$200,000 Completed
$314,000 Completed
$753,100 Completed
Redlands Institute, University
of Redlands $350,000 Completed
Randel Wildlife Consulting,
Inc. $606,257 Completed
Redlands Institute, University
of Redlands
Shawn Smallwood, sole
proprietor
UC Davis
$563,776 Completed
$716,596 Completed
$299,970 Completed
Recommendations 27-29: Create an Interagency Clean Energy Financing Working
Group, Support Extension of Federal Tax Credits, and Study the Effectiveness and
Impacts of the Property Tax Exclusion
Recommendations 27, 28, and 29 focused on the need for providing clean energy financing
programs, leveraging those programs, increasing public awareness of financing options, and
supporting the extension of federal tax credits for renewables.
The extension of federal tax credits remains a major issue, particularly for solar installations.
The Federal Investment Tax Credit is at 30 percent for residential and commercial systems
placed in service before December 31, 2016. After that date, the commercial credit drops to
10 percent, and the residential credit drops to zero, which will likely have an adverse effect
on residential solar development. In addition, there are continuing concerns with the boombust
cycles seen with the federal Production Tax Credit as it expires and then is (or is not)
extended and the effect on the wind industry.
There has been little progress on creating a clean energy financing working group or
evaluating the property tax exclusion, but there has been movement on helping to finance
customer-side renewable projects through property-assessed clean energy (PACE)
programs. In 2013, Senate Bill 96 directed the California Alternative Energy and Advanced
Transportation Financing Authority (CAEATFA) to develop the PACE Loss Reserve
Program to reduce the risk to mortgage lenders from residential PACE financing for energy
A-29

efficiency or distributed renewable installations. The Energy Commission provided $10
million for CAEATFA’s Loss Reserve, which makes first mortgage lenders whole for any
losses in a foreclosure or a forced sale attributed to a PACE lien. According to the
CAEATFA website, as of March 2015, there were more than 24,000 residential PACE
financings valued at about $500 million covered by the program, and no claims on the loss
reserve to date. 500 CAEATFA initially estimated the loss reserve would last 8 to 12 years but
is reevaluating that now that the program has been active for almost a year.
Recommendation 30: Modify the Clean Energy Business Financing Program
The Energy Commission’s Clean Energy Business Financing Program was originally funded
under the American Recovery and Reinvestment Act of 2009. Unfortunately, the program
experienced difficulties with funded projects not achieving their goals, and eventually the
program became too cumbersome for the Energy Commission to administer given the
demands of private sector loans. The Energy Commission is working to transfer remaining
program funds to the Department of General Services for administration of the funds.
Recommendation 31: Develop Marketing Outreach Plan for Energy Conservation
Assistance Account Programs
Recommendation 31 was to develop a marketing outreach plan for the Energy
Commission’s Energy Conservation Assistance Account (ECAA) program. At the time the
Renewable Action Plan was published, few local entities were taking advantage of the
ECAA program to finance renewable energy projects because the requirements for energy
payback periods did not accommodate the longer payback periods typical of renewable
installations.
In 2013, the ECAA loan payback period was changed in statute from 15 to 20 years, which
has allowed more loan applicants with solar projects to qualify for funding. Since 2013, the
Energy Commission has funded 26 ECAA loans that include PV installations, which
indicates that local agencies are more interested in taking advantage of the program.
The ECAA program also received additional funds as a result of Proposition 39 that have
been allocated to zero interest rate loans and energy audits for K-12 schools and community
colleges. The ECAA program also has been allocated funding from the Greenhouse Gas
Reduction Fund for eligible state-owned and operated facilities and the University of
California and California State University for energy efficiency and renewable energy
projects, with emphasis placed on projects within, or benefiting, a disadvantaged
community. The lower interest rates offered by the program elements funded through
500 California Alternative Energy and Advanced Transportation Financing Authority, Property
Assessed Clean Energy (PACE) Loss Reserve Program,
http://www.treasurer.ca.gov/CAEATFA/pace/activity.asp, accessed June 18, 2015.
A-30

Proposition 39 and the Greenhouse Gas Reduction Fund may make these programs more
attractive for applicants seeking to install renewable systems.
A-31

APPENDIX B:
California and Washington Crude-by-Rail Projects
Excluding the Plains All American crude-by-rail (CBR) facility near Taft (Kern County),
there is 58,000 barrels per day of permitted CBR receiving capacity in California. (See
below.) The Plains CBR facility is the only one in California that can receive one unit train
per day.
ALREADY OPERATIONAL FACILITIES – Receipt Capability in Thousands of Barrels
Per Day
SAV Patriot-Sacramento (PR) 10 Permit rescinded
KinderMorgan-Richmond 16
Kern Oil-Bakersfield 26
Plains-Bakersfield 65 Operational November 2014
Tesoro-Carson 3
Alon-Long Beach 10
ExxonMobil-Vernon 3
There is one CBR project (Alon-Bakersfield) that has completed the permit review, yet not
started construction. In addition, there four other projects either still undergoing permit
review or still in the development phase.
PROPOSED FACILITIES (all large) – Receipt Capability in Thousands of Barrels Per Day
Valero-Benicia (SP) 70 EIR Process
Phillips66-Santa Maria (SP) 37 EIR Process
Alon-Bakersfield (APNC) 150 Permit issued September 9, 2014
Targa-Stockton (SP) 65 Not yet completed marine terminal approval &
upgrades
Questar-Coachella Valley (PP) 120 Company performing engineering analysis
Northern California
WesPac Energy Project – Pittsburg – Revised Permit Review 501
• Will no longer include rail access
• Still plan marine terminal for receipt and loading—average of 192,000 BPD
• Connection to KLM pipeline– access to Valero, Shell, Tesoro and Phillips 66
refineries
• Connection to idle San Pablo Bay Pipeline– access to Shell, Tesoro and Phillips 66
refineries
501 http://www.ci.pittsburg.ca.us/index.aspx?page=700.
B-1

• Notice of Preparation (NOP) of a Second Recirculated Draft EIR released
• Construction could be completed within 18 months of receiving all permits
• Lead agency – City of Pittsburg
• Could be operational by 2017
Valero – Benicia Crude Oil by Rail Project - Undergoing Permit Approval 502
• Benicia refinery
• Up to 100 rail cars per day or 70,000 BPD
• Recirculated Draft Environmental Impact Report released August 31, 2015
• Construction would take six months
• Project will require approval of the City of Benicia
• Could be operational by 2016
Central California
Phillips 66 – Santa Maria Refinery – Undergoing Permit Approval 503
• Average of 37,142 BPD
• Planning and Building Department is working toward releasing a Final
Environmental Impact Report
• Construction expected to require 9–10 months to complete
• Project will require approval of the San Luis Obispo County Planning Commission
• Could be operational by 2016
Bakersfield Region
Alon Crude Flexibility Project – Permits Approved
• Alon-Bakersfield Refinery
• 2 unit trains per day—104 rail cars per unit train
• 150,000 BPD offloading capacity
• Will be able to receive heavy crude oil
• Oil tankage connected to main crude oil trunk lines—transfer to other refineries in
Northern and Southern California
• Kern County Board of Supervisors approved permits for the project on September 9,
2014
• Contract awarded for initial engineering work – May 2015
• Construction has not commenced but would take nine months to complete
502 http://www.ci.benicia.ca.us/index.asp?Type=B_BASIC&SEC={FDE9A332-542E-44C1-BBD0-
A94C288675FD}.
503
http://www.slocounty.ca.gov/planning/environmental/EnvironmentalNotices/Phillips_66_Company_
Rail_Spur_Extension_Project.htm.
B-2

• Could be operational by 2016
Plains All American – Bakersfield Crude Terminal – Operational
• Up to 65,000 BPD
• Connection to additional crude oil line via new six-mile pipeline
• Initial delivery during November 2014
• Poor rail economics have limited deliveries
• Litigation underway regarding permit
The Energy Commission is also monitoring the progress of two other potential CBR projects,
one in Stockton (Northern California) and another in Riverside County (Southern
California). The Targa project in the Port of Stockton is designed to receive CBR cargoes and
transfer the oil to marine vessels for delivery to California refineries. The planned capacity
of the facility is nearly 65,000 BPD. Another project being tracked by the Energy
Commission is the Questar/Spectra CBR project that is designed to import up to 120,000
BPD of crude oil into a yet-to-be-determined facility in Riverside County that would then be
off-loaded into storage tanks before being shipped via a combination of existing and new
pipelines to refineries in Southern California. These two CBR proposals have the potential to
contribute an additional 185,000 BPD to California’s CBR receiving capacity by end of 2017.
Washington CBR Projects
Northwest Washington
BP – Cherry Point Refinery (1) – Operational
• Up to 60,000 BPD
• Permits received from Whatcom County, Washington, on April 13, 2013
• Operational December 26, 2013
Tesoro – Anacortes Refinery (2) – Operational
• Up to 50,000 BPD
• 40 percent of refinery crude oil supply
• Operational September 2012
Shell – Anacortes Refinery (3) – Permit Review
• Up to 62,000 BPD
• Will require permits from Army Corps of Engineers, Washington Department of
Ecology, and Skagit County
• Draft EIS to be developed after Shell appeal to obtain a Mitigated Determination of
Non-Significance was denied in May 2015
• Could be operational by late 2016
Phillips 66 – Ferndale Refinery (4) – Operational
• Up to 20,000 BPD, mixed freight cars
B-3

• Permits for expansion to 40,000 BPD received from Whatcom County, Washington
during 2014
Figure 69: Northwest Washington CBR Facilities
1
4
1
4
2
3
2
3
Source: WSDOT State Rail & Marine Office map and Energy Commission
Southwest Washington and Northwest Oregon
Global Partners LP – Clatskanie, Oregon (5) – Operational
• Original crude oil transloading capability up to 28,600 BPD
• Revised permit issued August 19, 2014; increases capacity to 120,000 BPD
• Deepwater marine terminal
• Operational November 2012
Imperium Renewables, Port of Grays Harbor Project (6) – Permit Review
• Rail receipts of unit trains and loading of marine vessels
• Capacity up to 75,000 BPD
• Shoreline Substantial Development Permit was issued June 17, 2013
• SSDP remanded and SEPA determination invalidated by State Shorelines Hearing
Board on November 12, 2013
B-4

• Environmental impact statements (EIS) being developed – Washington Department
of Ecology and City of Hoquiam are lead agencies for the project permit review
• Start-up date uncertain
NusStar, Port of Vancouver (7) – Permit Review
• Rail receipts of unit trains and loading of marine vessels
• Capacity up to 41,000 BPD
• Permit review underway
• Initial start-up date uncertain
Targa Sound, Tacoma Terminal (8) – Permit Review
• Rail receipts of unit trains and loading of marine vessels
• Capacity up to 41,000 BPD
• Permit review underway
• Start-up date uncertain
Tesoro – Savages, Port of Vancouver Project (9) – Permit Review
• Rail receipts of unit trains and loading of marine vessels
• Initial capacity up to 120,000 BPD
• Tesoro will have offtake rights to 60,000 BPD
• Expansion capability of up to 360,000 BPD
• Revised draft EIS to be released late November 2015
• Lead agency– Energy Facility Site Evaluation Council
• Start-up could occur by 2017
U.S. Oil & Refining – Tacoma Refinery (10) – Operational and Planned Expansion
• Up to 6,900 BPD, mixed freight cars
• Operational April 2013
• Seeking permits to expand capacity to 48,000 BPD
Westway Terminals, Port of Grays Harbor Project (11) – Permit Review
• Rail receipts of unit trains and loading of marine vessels
• Capacity up to 26,000 BPD for first phase of project, up to 48,900 BPD second phase
• Shoreline Substantial Development Permit issued on April 26, 2013
• SSDP remanded and SEPA determination invalidated by State Shorelines Hearing
Board on November 12, 2013
• EIS being developed – Washington Department of Ecology and City of Hoquiam are
lead agencies for the project permit review
• Start-Up date uncertain; construction would take 12–16 months to complete once all
permits have been received
B-5

Figure 70: Southwest Washington and Northwest Oregon CBR Facilities
8
10
6
11
5
9 7
Source: WSDOT State Rail & Marine Office map and Energy Commission
B-6

APPENDIX C:
Crude-By-Rail Chronology of Safety-Related Actions
August 31, 2011
Association of America Railroads issues Casualty
Prevention Circular 1232 (CPC 1232). Requires all manufacturers to
construct rail tank cars to upgraded standards beginning October 10,
2011. 504
August 7, 2013 Federal Railroad Administration issues Emergency Order No. 28.
Primarily requires trains transporting crude oil and other flammable
liquids to be manned at all times whether the train is temporarily
idled on side tracks. 505 Intended to prevent an unattended train from
rolling away from its idle position and derailing, as was the case with
the Lac Mégantic, Quebec, Canada, accident.
September 6, 2013
Pipeline and Hazardous Materials Safety Administration issues an
Advance Notice of Proposed Rulemaking covering standards for rail
tank cars and operations of trains transporting flammable liquids. 506
February 21, 2014
Department of Transportation sends a letter to the Association of
American Railroads requesting specific voluntary steps to be
undertaken to reduce the risk of derailment and release of crude oil. 507
Actions include:
504 Crude Oil Tank Cars – Economics, Specification, Supply, Regulation, and Risk: GATX, February 13,
2013, slide 17, http://www.crude-by-rail-destinations-summit.com/media/downloads/127-paultitterton-vice-president-and-group-executive-fleet-management-marketing-and-governmentaffairs.pdf.
505 “Emergency Order Establishing Additional Requirements for Attendance and Securement of
Certain Freight Trains and Vehicles on Mainline Track or Mainline Siding Outside of a Yard or
Terminal,” Federal Register, Vol. 78, No. 152, August 7, 2013, pages 48218-48224,
https://www.fra.dot.gov/eLib/details/L04719.
506 “Hazardous Materials: Rail Petitions and Recommendations To Improve the Safety of Railroad
Tank Car Transportation (RRR),” Federal Register, Vol. 78, No. 173, September 6, 2013, pages 54849-
54861, http://www.gpo.gov/fdsys/pkg/FR-2013-09-06/pdf/2013-21621.pdf.
507 A copy of the letter can be found at http://www.dot.gov/briefing-room/letter-associationamerican-railroads.
C-1

• Maximum speeds of 50 miles per hour.
• Maximum speed reduced to 40 miles per hour for any trains
shipping crude oil using pre-CPC 1232 rail tank cars.
• Operational changes to improve emergency braking
capability.
• Increased inspections.
• Installation of devices to detect defective bearings.
April 23, 2014
Transport Canada issues a Protective Direction that prohibits older
style rail tank cars from transporting Class 3 flammable liquids such
as crude oil and ethanol. Further, pre-CPC 1232 rail tank cars are to be
phased out of service within three years or retrofitted to meet stricter
standards. In addition, Transport Minister issues an order limiting the
speeds of trains transporting crude oil and ethanol to 50 miles per
hour (MO 14-01). 508
May 7, 2014
U.S. Department of Transportation issues an Emergency Order OST-
2014-0067 requiring railroad companies to alert State Emergency
Response Commission representatives of the specific counties that
trains carrying Bakken crude oil in excess of one million gallons will
traverse. 509 In the case of California that would be the Governor’s
Office of Emergency Services.
June 10, 2014
California Interagency Rail Safety Working Group issues report on
crude-by-rail activities that contain extensive recommendation to
federal and state agencies directed at improving rail safety of
flammable liquid transportation. 510
508 Minister of Transport Order Pursuant to Section 19 of the Railway Safety Act, April 23, 2014,
http://www.tc.gc.ca/eng/mediaroom/ministerial-order-railway-7491.html.
509 A copy of the Emergency Order can be found at
https://www.fra.dot.gov/eLib/details/L05225#p1_z5_gD_lSO_y2013_y2014.
510 Oil by Rail Safety in California, State of California Interagency Rail Safety Working Group, June 10,
2014, http://www.caloes.ca.gov/FireRescueSite/Documents/IRSWG-
Oil%20By%20Rail%20Safety%20in%20California.pdf.
C-2

June 20, 2014 Governor Brown signs into law Senate Bill 861 (Corbett, Chapter 35,
Statues of 2014) that, among other issues, expands the role of the
California Office of Spill Prevention and Response from coastal
responsibility to a statewide responsibility. 511 The Office of Spill
Prevention and Response has initiated activities to develop new rules
that will be used to enforce the legislation. A fee assessed for crude oil
delivered to California refineries will be used to fund 38 permanent
staff. 512
June 25, 2014
Energy Commission convenes a public workshop of various federal,
state, private, and public stakeholders to discuss emerging trends in
crude oil transportation, recent developments of rail-related safety
regulations, and expanded oversight of crude-by-rail activities by
various state agencies. 513
California Interagency Rail Safety Working Group unveils its
interactive rail risk and response map tool. This software “…helps
identify areas along rail routes in California with potential higher
vulnerability and shows nearby emergency response capacity”. 514
August 1, 2014
Pipeline and Hazardous Materials Safety Administration issues
Notice of Proposed Rulemaking covering standards for rail tank cars
and operations of trains transporting flammable liquids. 515 Primary
proposed regulatory changes:
511 http://www.leginfo.ca.gov/pub/13-14/bill/sen/sb_0851-0900/sb_861_bill_20140620_chaptered.pdf.
512 A description of OSPR responsibilities and new activities in response to SB 861 may be viewed at
https://www.wildlife.ca.gov/OSPR/About.
513 Lead Commissioner Workshop on Trends in Sources of Crude Oil, California Energy Commission, June
25, 2014. The workshop proceeding can be found at
http://www.energy.ca.gov/2014_energypolicy/documents/#06252014.
514 The Rail Risk & Response Map is at
http://california.maps.arcgis.com/apps/OnePane/basicviewer/index.html?appid=928033ed043148598f7
e511a95072b89.
515 “Hazardous Materials: Enhanced Tank Car Standards and Operational Controls for High-Hazard
Flammable Trains,” Federal Register, Vol. 79, No. 148, August 1, 2014, pages 45016-45079. The
presentation can be found at http://www.gpo.gov/fdsys/pkg/FR-2014-08-01/pdf/2014-17764.pdf.
C-3

• Designates trains transporting Class 3 flammable liquids (such
as crude oil and ethanol) as High-Hazard Flammable Trains
(HHFTs.)
• Limits all HHFT to maximum speed of 50 miles per hour
along all routes.
• Seeks comments on proposed lower maximum speeds under
various circumstances.
• Requires railroads to undertake analysis of HHFT routes to
identify the ones with the least risk.
• Requires adoption of new operating procedures and/or
equipment to improve braking responses to emergency stops.
• Requires new construction standards for all rail tank cars
constructed after October 2015 that would be used to transport
Class 3 flammable liquids – new Department of
Transportation Specification 117. 516
Requires all noncomplying rail tank cars (legacy fleet) to be
repurposed, retired, or refurbished to meet the stricter standards by
October 1, 2017, for the most flammable commodities (Packing
Group I).
September 9, 2014
Federal Railroad Administration issues a Notice of Proposed
Rulemaking to codify many of the directives specified in Emergency
Order 28 related to the securement of unattended locomotives. 517
These measures are designed to prevent trains carrying certain
hazardous materials (such as crude oil) from being unmanned while
on sidings or mainline track. Exceptions are allowed if train crews
follow various additional safety and securement protocols.
516 According to William Finn of the Railway Supply Institute, there were 43,750 rail tank cars in
crude oil service at the end of 2013 of which 14,350 rail tank cars were compliant with the more
stringent CPC 1232 standards. In addition, there were 29,850 rail tank cars in ethanol service at that
time of which 500 were compliant with the more stringent CPC 1232 standards. By the end of 2015,
the number of rail tank cars meeting the CBC 1232 standards is expected to number 57,200 at the
current rate of construction. Mr. Finn’s presentation can be found at
http://www.energy.ca.gov/2014_energypolicy/documents/2014-06-
25_workshop/presentations/Finn_PPT_Updated.pdf.
517 “Securement of Unattended Equipment,” Federal Register, Vol. 79, No. 174, September 9, 2014,
pages 53356-53383. The document can be found at http://www.gpo.gov/fdsys/pkg/FR-2014-09-
09/pdf/2014-21253.pdf
C-4

December 9, 2014
March 15, 2015
May 1, 2015
August 3, 2015
The North Dakota Industrial Commission issues new standards
related to the treatment of Bakken crude oil to ensure that the more
volatile components are removed through application of heat or
pressure prior to being loaded into rail tank cars. New standards go
into effect on April 1, 2015 and limit the volatility of the treated crude
oil to a maximum of 13.7 pounds per square inch, lower than the
ASTM standard of 14.7 pounds per square inch. 518
California Governor’s Office of Emergency Services issues an updated
gap analysis report that “…outlines existing hazardous material
capabilities and emergency response resources operated by our local,
state, federal, industrial, and tribal partners, and may be available to
respond either directly or as part of a mutual aid request to an
accident resulting in a major hazardous materials release. It also
identifies gaps in adequate planning, training, and response
capabilities.” 519
Pipeline and Hazardous Materials Safety Administration and the
Federal Railroad Administration issue a Final Rule related to
improving the standards for rail tank cars used to transport crude oil
and ethanol, as well as operation of trains transporting such
materials. 520
The California Office of Spill Prevention and Response (OSPR) posts
emergency regulations to implement SB 861. The regulations cover
contingency plans, certificates of financial responsibility, and drills
and exercises requirements for the new inland entities now under
OSPR’s jurisdiction. 521
518 North Dakota Industrial Commission Order Number 25417, December 9, 2014. The document can
be found at https://www.dmr.nd.gov/oilgas/Approved-or25417.pdf
519 Updated Gap Analysis for Rail in California, Governor’s Office of Emergency Services, March 15,
2015. The document can be found at
http://www.caloes.ca.gov/FireRescueSite/Documents/Updated_Gap_Analysis_for_Rail_in_California
-20150313.pdf.
520 Rule Summary: Enhanced Tank Car Standards and Operational Controls for High-Hazard Flammable
Trains, U.S. Department of Transportation, May 1, 2015. See more at:
http://www.transportation.gov/mission/safety/rail-rule-summary#sthash.Cs7rjA9i.dpuf
521 The proposed OSPR regulations can be found at
https://www.wildlife.ca.gov/OSPR/Legal/Proposed-Regulations.
C-5

APPENDIX D:
Full List of ARFVTP Projects Analyzed by NREL for
2015 IEPR Update
Table 20: Full List of ARFVTP Projects Analyzed by NREL
Fuel Class
Project Categories
or Sub
Class
Fuel Delivery Infrastructure
Awards to 6/15
No.
($M)
Awards
Projects Evaluated in Benefits Analysis
No.
($M)
Number Units
Awards
40 Level 1
Electric Drive Charging
Infrastructure
Electric Drive $40.9 69 $40.9 69 9540 Level 2
132 DCFC
Hydrogen Fueling
Infrastructure
Hydrogen $83.5 37 $82.5 36 47 Stations
Natural Gas Fueling
Infrastructure
Natural Gas $16.0 44 $16.0 44 51 Stations
E85 Fueling Stations
Gasoline
Substitute
$14.6 4 $14.6 4 205 Stations
Upstream Infrastructure
Diesel
5 Facilities or
$4.0 4 $4.0 4
Substitute
Expansions
Hydrogen Fuel
Standards Development
Hydrogen $4.1 2 - - -
Fuel Delivery
Infrastructure Subtotal
$163.1 160 $158.0 157
Vehicles
Light-Duty Incentives,
109,661
Electric Drive $24.5 3 $24.5 3
CVRP
Rebates
Medium- Heavy-Duty
Incentives, HVIP
Electric Drive $4.0 1 $4.0 1 155 vehicles
Natural Gas Vehicle
Deployment Incentives
Natural Gas $71.2 5 $71.2 5 2826 vehicles
LPG Vehicle Deployment
Incentives
Propane $21.0 2 $21.0 2 509 vehicles
Light-Duty Demonstration Electric Drive $0.6 1 $0.6 1 50 LDVs
Medium- and Heavy-Duty
Vehicle Demonstration
Electric Drive $70.6 26 $70.6 26 Various 1
Fuel Cell Bus
Demonstration
Hydrogen $4.6 2 $2.4 1 1 bus
Medium- and Heavy-Duty
2 natural gas
Natural Gas $6.3 2 $6.3 2
Vehicle Demonstration
engine demos
Medium- and Heavy-Duty Gasoline
1 hybrid E85
$2.7 1 $2.7 1
Vehicle Demonstration Substitute
powertrain
Component
Demonstration
Hydrogen $4.4 2 $4.4 2 4 vans, 2 bus
Component
Demonstration
Electric Drive $20.6 9 $20.6 9 Various 2
Vehicle Manufacturing Electric Drive $34.5 10 $34.5 10 Various 3
Vehicles Subtotal $265 64 $262.8 63
D-1

Fuel Production
Bench Scale & Feasibility Biodiesel $5.0 1 - - -
Commercial Production Biomethane $43.5 10 $43.5 10 -
Bench Scale & Feasibility Biomethane $12.5 6 $12.5 6 -
Commercial Production
Diesel
Substitutes
$33.9 9 $33.9 9 -
Bench Scale & Feasibility
Diesel
Substitutes
$17.8 8 $17.8 8 -
Commercial Production
Gasoline
Substitute
$17.5 6 $17.5 6 -
Bench Scale & Feasibility
Gasoline
Substitute
$5.9 3 $5.9 3 -
Fuel Production
Subtotal
$136.1 43 $131.1 42
Other
PEV Regional Readiness Electric Drive $6.9 30 - - -
Regional Readiness Hydrogen $0.8 4 - - -
Sustainability Research Biofuels $2.1 2
Workforce Training and Workforce
Development
Training/Dev.
$25.2 3 - - -
Technical Assistance Program
and Analysis
Support
$13.9 14 - - -
Other Subtotal $48.9 53 - -
TOTAL $613.1 320 $551.9 262
Notes: (1) 12 HD hybrid hydraulic delivery trucks, 10 range-extender MD truck demo, 5 HD truck retrofits to PHEV, 1 class 8
hybrid natural gas truck, 1 all electric fleet at Air Force Base, 1 diverse fleet of 378 vehicles, 1 prototype class 4 all-electric,
feasibility and testing for 1 truck manufacturing facility, 1 CLEAN Truck Demo Program, 1 HD truck retrofits to pantograph
system; (2) 3 lithium battery production/assembly processes, 1 electric motorcycle powertrain, 2 battery
management/communication systems, 2 electric drive manufacturing and assembly processes, and 4 electric drive
demonstration projects including 14 MD trucks, 17 class 6 trucks, 6 schools buses, and 7 walk-in vans; (3) 1 new production
line for electric motorcycle, 1 BEV manufacturing and assembly expansion, 1 new manufacturing facility for M/HD BEVs, 1
manufacturing expansion for range-extended MD trucks, 1 pilot production line for flexible all-electric platform, and 1 pilot
production line for powertrain control systems. (4) 6 of 26 projects
Table 20 shows ARFVTP investments by each 2015-2016 Investment Plan category, along
with the number of projects or vehicles and fueling infrastructure funded to date. It also
shows cumulative completion of ARFVTP projects. On a dollar basis, 29 percent of projects
are complete ($172 million out of $589 million in cumulative contract awards).
D-2

Table 21: Cumulative ARFVTP Investments Through June 30, 2015, by Investment Plan
Category
Category
Alternative
Fuel
Production
Alternative
Fuel
Infrastructure
Alternative
Fuel and
Advanced
Technology
Vehicles
Related
Needs and
Opportunities
Funded Activity
Cumulative
Awards to
Date
(in
millions)*
No. of Projects
or Units
Percent
Complete
(% dollar
basis)
Biomethane Production $50.9 15 Projects 28.3
Gasoline Substitutes Production $29.3 14 Projects 11.6
Diesel Substitutes Production $57.4 20 Projects 8.4
Electric Vehicle Charging
7,515 Charging
$40.7
Infrastructure
Stations 34.4
Hydrogen Refueling Infrastructure $88.0
49 Fueling
Stations 0.0**
E85 Fueling Infrastructure $13.7
158 Fueling
Stations 16.8
Upstream Biodiesel Infrastructure $4.0
4 Infrastructure
Sites 97.5
Natural Gas Fueling Infrastructure $15.5
50 Fueling
Stations 49.0
Natural Gas Vehicle Deployment** $57.0
2,956 Trucks and
Cars 74.7
Propane Vehicle Deployment** $6.4 514 Trucks 100.0
Light-Duty Electric Vehicle
$25.1 10,700 Cars
Deployment
80.1
Medium- and Heavy-Duty Electric
$4.0 150 Trucks
Vehicle Deployment
100.0
Medium- and Heavy-Duty Vehicle
Technology Demonstration and
Scale-Up
$89.7
42
Demonstrations
11.7
Manufacturing $57.0
22 Manufacturing
Projects 24.9
Emerging Opportunities † †
Workforce Training and
$25.2 55 Recipients
Development
75.0
Fuel Standards and Equipment
$3.9 1 Project
Certification
100.0
Sustainability Studies $2.1 2 Projects 0.0
Regional Alternative Fuel Readiness
34 Regional
$7.6
and Planning
Plans 21.1
Centers for Alternative Fuels $5.8 5 Centers 0.0
Technical Assistance and Program
$5.6 5 Agreements
Evaluation
5.4
Total $588.9 29.3
Source: California Energy Commission * Includes all agreements that have been approved at an Energy Commission Business
Meeting, or are expected for Business Meeting approval following publication of a Notice of Proposed Award. ** Although three
Energy Commission-funded hydrogen stations are operational, final invoices have not been paid out due to the multiple
stations per grant award.]
D-3

APPENDIX E:
Status of Past IEPR Nuclear Policy
Recommendations
Table 22: Status of Past IEPR Nuclear Policy Recommendations
2013 IEPR – Diablo Canyon Power Plant Status
2013-
6-01
PG&E
PG&E should continue to provide updates on its progress in
completing the AB 1632 Report‐recommended studies to the
Energy Commission and make its findings and conclusions
available to the Energy Commission, the CPUC, and the NRC
during their reviews of the Diablo Canyon license renewal
application.
Central Coastal
California
Seismic Imaging
Project (CCCSIP)
completed in
September 2014
and made
available to state
and federal
regulators.
2013-
6-02
PG&E
PG&E should provide updated evacuation time estimates,
including a real‐time evacuation scenario following a seismic
event, and submit to the Energy Commission as part of the
IEPR reporting process.
Update of
Evacuation Time
Estimate report is
underway;
updated report
will incorporate
an evacuation
time estimate
following a
seismic event.
2013-
6-03
PG&E
Based on mounting clean‐up costs for the 2011 Fukushima
accident, PG&E should provide to the Energy Commission and
CPUC a comprehensive study on whether the Price‐Anderson
liability coverage for a severe event at Diablo Canyon would be
adequate to cover liabilities resulting from a large offsite
release of radioactive materials in San Luis Obispo County and
adjacent counties included in the Ingestion Pathway Zone, and
if not, identify and quantify other funding sources that would
be necessary to cover any shortfall. The CPUC should consider
requiring PG&E to complete such a study as a condition of
future License Renewal funding approval.
E-1
A study of all
sources of
funding available
(primary and
secondary
insurance) to
meet any
potential
liabilities of a
severe event at
Diablo Canyon
has not been
completed. An
act of Congress is
required to
provide

additional funds
if primary and
secondary
insurance funds
are insufficient.
2013-
6-04
PG&E
To help ensure plant reliability and minimize costs to
ratepayers, the Nuclear Regulatory Commission should, in an
open, timely and transparent process, ensure that all seismic
hazard analyses for Diablo Canyon are evaluated against the
licensed design basis elements for the Design Earthquake and
the Double Design Earthquake, in addition to the Hosgri
earthquake element prior to consideration or approval of the
Diablo Canyon license renewal application. As part of the IEPR
reporting process, PG&E should update the Energy
Commission on the progress of this evaluation and provide the
final product to the Energy Commission when it is completed.
PG&E completed
a Probabilistic
Seismic Hazard
Analysis (PSHA)
study and
submitted it to
the NRC in
March 2015.
2013-
6-05
PG&E
PG&E should, as expeditiously as possible, bring Diablo
Canyon into compliance with the applicable 2004 National Fire
Protection Agency fire protection regulations and report to the
Energy Commission on its progress until full compliance is
achieved.
A license
amendment
request
submitted to the
NRC in June 2013
would transition
the fire protection
program to a riskinformed,
performancebased
alternative.
NRC approval is
pending.
2013-
6-06
PG&E
CPUC
PG&E should evaluate the potential long‐term impacts and
projected costs of spent fuel storage in pools versus dry cask
storage of higher burn‐up fuels in densely packed pools, and
the potential degradation of fuels and package integrity during
long‐term wet and dry storage and transportation offsite and
submit the findings to the Energy Commission and CPUC. The
Energy Commission recommends that the CPUC require
expedited transfer of spent fuel assemblies from wet pools to
dry cask storage be included in the decommissioning process
and the costs of this expedited removal be included in
decommissioning funds before license renewal funding is
granted.
No stand-alone
cost-benefit
analysis of wet
vs. dry storage
has been
performed. Spent
fuel is stored in
pools for a
minimum of five
years before
being placed in
dry cask storage.
2013-
6-07
PG&E
To help ensure plant reliability and minimize costs to
ratepayers, prior to reactivating the Diablo Canyon license
renewal application with the Nuclear Regulatory Commission,
No stand-alone
study was
E-2

PG&E should provide to the Energy Commission and CPUC
an evaluation of the structural integrity of the concrete and
reinforcing steel in the spent fuel pools, including any
increased vulnerability to damage resulting from a seismic
event.
performed.
2013-
6-08
PG&E
PG&E should perform, and report to the Energy Commission
and CPUC as part of the IEPR reporting process, an evaluation
of the inventory of the spent fuel pools to determine the
maximum number of spent fuel bundles it can move on a per
year basis from the spent fuel pools into dry cask storage,
taking into consideration the following constraints:
• Thermal limits of the dry casks imposing a minimum
threshold on the age of the spent fuels
• Federal requirements on older spent fuels surrounding
newer spent fuels
• Availability of dry casks
• Building schedule(s) of dry cask storage pads
• Coordination of refueling outages and dry casks
loading schedules
• Availability of plant staff and contractors for dry cask
loadings.
Spent fuel is
stored in spent
fuel pools for
minimum of five
years. Spent fuel
will be
transferred to dry
casks during
2015-2016 to
achieve a
minimum
complement of
used fuel
assemblies that
meet NRC
spacing
requirements.
Future loading of
spent fuel into
dry casks will be
done
approximately
every other year
to maintain the
NRC minimum.
2013-
6-09
PG&E
To reduce the volume of spent fuel packed into Diablo
Canyon’s storage pools (and consequently the radioactive
material available for dispersal in the event of an accident or
sabotage), PG&E should, as soon as practicable and while
maintaining compliance with Nuclear Regulatory Commission
spent fuel cask and pool storage requirements, transfer spent
fuel from the pools into dry casks and report to the Energy
Commission on its progress until the pools have been returned
to open racking arrangements.
See above.
2013-
6-10
DCISC
PG&E
The Diablo Canyon Independent Safety Committee should
monitor PG&E’s progress in completing the root cause
evaluation of laminar flaws on the Unit 2 pressurizer nozzles
and identification of required corrective actions over the next
DCISC followed
this issue. A root
case evaluation
was completed
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cycle of operation, and follow the issue until it is resolved.
and reported to
NRC. A more
comprehensive
flaw analysis will
also be
completed.
2013 IEPR – San Onofre Nuclear Generating Station Category
2013-
6-11
SCE
SCE should complete the seismic studies identified in Advice
Letter 2930‐E, approved by the CPUC Energy Division on
September 18, 2013, and provide results of the studies to the
Energy Commission and CPUC.
Field studies
have been
completed. A
final report is
expected by the
end of 2015.
2013-
6-12
SCE
SCE should, as soon as practicable, expand the Independent
Spent Fuel Storage Installation and transfer spent fuel from
pools into dry casks, while maintaining compliance with
Nuclear Regulatory Commission spent fuel cask and pool
storage requirements and report to the Energy Commission on
its progress until all spent fuel is transferred to dry cask
storage.
Awarded a
contract to Holtec
International for
the construction
of a HI-STORM
below ground
storage facility.
Transfer of spent
fuel from pools to
dry casks
expected to be
completed by
2019.
2013-
6-13
SCE
SCE should submit a decommissioning plan to the Nuclear
Regulatory Commission as soon as possible and proceed with
decommissioning of San Onofre swiftly, providing progress
updates to the Energy Commission until decommissioning of
the site is completed.
A Post-Shutdown
Decommissioning
Activities Report,
Irradiated Fuel
Management
Plan, and Site-
Specific
Decommissioning
Cost Estimate
were submitted
to the NRC in
September 2014.
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2013 IEPR – Nuclear Waste Category
2013-
6-14
CEC
The Energy Commission will continue to monitor federal
nuclear waste management program activities and represent
California in the reactivated Yucca Mountain licensing
proceeding to ensure that California’s interests are protected
regarding potential groundwater and spent fuel transportation
impacts in California.
Ongoing.
2013-
6-15
CEC
The Energy Commission supports federal efforts to develop an
integrated system for management and disposal of nuclear
waste, including the establishment of a new, consent‐based
approach to siting future nuclear waste management facilities.
Federal
legislation
proposed in
March 2015 to
implement an
interim
consolidated
storage strategy.
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